Northern States Power 10-K 2008 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

Or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-31387

NORTHERN STATES POWER COMPANY

(Exact name of registrant as specified in its charter)

Minnesota	41-1967505
State or other jurisdiction of	(I.R.S. Employer
Incorporation or organization	Identification No.)

414 Nicollet Mall, Minneapolis, Minnesota  55401

(Address of principal executive offices)

Registrant’s Telephone number, including area code:  612-330-5500

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to section 12(g) of the Act:  Common Stock

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes  o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes  x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    x Yes   o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “ smaller reporting company” in Rule 12b-2 of the Exchange Act.

o Large accelerated filer  o Accelerated filer  x Non-accelerated filer (Do not check if a smaller reporting company)
o Smaller Reporting Company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    o Yes   x No

As of March 2, 2009, 1,000,000 shares of common stock, par value $0.01 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2009 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

Northern States Power Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

INDEX

This Form 10-K is filed by Northern States Power Co., a Minnesota corporation (NSP-Minnesota).  NSP-Minnesota is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC).  This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NMC	Nuclear Management Co., a wholly owned subsidiary of NSP Nuclear Corporation
NSP-Minnesota	Northern States Power Co., a Minnesota corporation
NSP-Wisconsin	Northern States Power Co., a Wisconsin corporation
PSCo	Public Service Company of Colorado, a Colorado corporation
SPS	Southwestern Public Service Co., a New Mexico corporation
utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy	Xcel Energy Inc., a Minnesota corporation
Federal and State Regulatory Agencies
DOE	United States Department of Energy
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas and the sale of electricity at wholesale, in interstate commerce, including the sale of electricity at market-based rates.
IRS	Internal Revenue Service
MPCA	Minnesota Pollution Control Agency
MPUC	Minnesota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in Minnesota. The MPUC also has jurisdiction over the capital structure and issuance of securities by NSP-Minnesota.
NERC	North American Electric Reliability Corporation. A self-regulatory organization, subject to oversight by the U.S. Federal Energy Regulatory Commission and government authorities in Canada, to develop and enforce reliability standards.
NDPSC	North Dakota Public Service Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in North Dakota.
NRC	Nuclear Regulatory Commission. The federal agency that regulates the operation of nuclear power plants.
PSCW	Public Service Commission of Wisconsin. The state agency that regulates the retail rates, services, securities issuances and other aspects of NSP-Wisconsin’s operations in Wisconsin.
SDPUC	South Dakota Public Utilities Commission. The state agency that regulates the retail rates, services and other aspects of NSP-Minnesota’s operations in South Dakota.
SEC	Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
DSM	Demand-side management. Energy conservation, weatherization and other programs to conserve or manage energy use by customers.
FCA	Fuel clause adjustment. A clause included in NSP-Minnesota’s retail electric rate schedules that provides for prospective monthly rate adjustments to reflect the actual cost of electric fuel and purchased energy compared to a prior forecast. The difference between the electric costs collected through the FCA rates and the actual costs incurred in a month are collected or refunded in a subsequent period.
PGA	Purchased gas adjustment. A clause included in NSP-Minnesota’s retail gas rate schedules that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased gas. The annual difference between

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	the gas costs collected through PGA rates and the actual gas costs is collected or refunded over the subsequent 12-month period.
TCR	Transmission cost recovery adjustment. Allows NSP-Minnesota to recover the cost of transmission facilities not included in the determination of NSP-Minnesota’s base electric rates in retail electric rates in Minnesota. The TCR was approved by the MPUC in 2006 to be effective in 2007 and will be revised annually as new transmission investments and costs are incurred.
Other Terms and Abbreviations
AFDC	Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ	Administrative law judge. A judge presiding over regulatory proceedings.
ARO	Asset Retirement Obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
BART	Best Available Retrofit Technology
CO2	Carbon dioxide
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CapX 2020	An alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort.
COLI	Corporate-owned life insurance
decommissioning	The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of license. Nuclear power plants are required by the NRC to set aside funds for their decommissioning costs during operation.
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	·	An underlying and a notional amount or payment provision or both,
	·	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors, and
	·	Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution	The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings
FTRs	Financial Transmission Rights. Used to hedge the costs associated with transmission congestion.
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatts (capacity) or megawatt hours (energy).
GHG	Greenhouse Gas
JOA	Joint operating agreement among the Utility Subsidiaries
LIBOR	London Interbank Offered Rate
LNG	Liquefied natural gas. Natural gas that has been converted to a liquid.
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MERP	Metropolitan emissions reduction project.
MGP	Manufactured gas plant.
MISO	Midwest Independent Transmission System Operator, Inc.

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Moody’s	Moody’s Investor Services Inc.
native load	The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric or natural gas service created by statute or long-term contract.
natural gas	A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.
NOx	Nitrogen oxide
nonutility	All items of revenue, expense and investment not associated, either by direct assignment or by allocation, with providing service to the utility customer.
PFS	Private Fuel Storage, LLC. A consortium of private parties (including NSP-Minnesota) working to establish a private facility for interim storage of spent nuclear fuel.
PUHCA	Public Utility Holding Company Act of 1935. Enacted to regulate the corporate structure and financial operations of utility holding companies.
QF	Qualifying facility. As defined under the Public Utility Regulatory Policies Act of 1978, a QF sells power to a regulated utility at a price equal to that which it would otherwise pay if it were to build its own power plant or buy power from another source.
Rate base	The investor-owned plant facilities for generation, transmission and distribution and other assets used in supplying utility service to the consumer.
ROE	Return on equity
RTO	Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SFAS	Statement of Financial Accounting Standards
SO2	Sulfur dioxide
Standard & Poor’s	Standard & Poor’s Ratings Services
TEMT	Transmission and Energy Markets Tariff. The tariff requires RTOs such as the MISO to provide real-time energy imbalance services and a market-based mechanism for congestion management.
unbilled revenues	Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying	A specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates or other variable, including the occurrence or nonoccurrence of a specified event such as a scheduled payment under a contract.
wheeling or transmission	An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
Measurements
Btu	British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
Bcf	Billion cubic feet
KV	Kilovolts
KW	Kilowatts
Kwh	Kilowatt hours
MMBtu	One million Btus
MW	Megawatts (one MW equals one thousand KW)
Watt	A measure of power production or usage.

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COMPANY OVERVIEW

NSP-Minnesota was incorporated in 2000 under the laws of Minnesota.  NSP-Minnesota is an operating utility engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota.  The wholesale customers served by NSP-Minnesota comprised approximately 9 percent of its total sales in 2008.  NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota.  NSP-Minnesota provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 0.5 million customers.  Approximately 89 percent of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2008.  Generally, NSP-Minnesota’s earnings range from approximately 40 percent to 50 percent of Xcel Energy’s consolidated net income.

The electric production and transmission system of NSP-Minnesota is managed as an integrated system with that of NSP-Wisconsin, jointly referred to as the NSP System.  The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin.  A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Co., which holds real estate; and NSP Nuclear Corp., which owns NMC.

NSP-Minnesota conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other.  Comparative segment revenues and related financial information for fiscal 2008, 2007 and 2006 are set forth in Note 17 to the accompanying consolidated financial statements.

NSP-Minnesota focuses on growing through investments in electric and natural gas rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers.  NSP-Minnesota files periodic rate cases or establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations.

ELECTRIC UTILITY OPERATIONS

Overview

Climate Change and Clean Energy —Like most other utilities, NSP-Minnesota is subject to a significant array of environmental regulations focused on many different aspects of its operations.  There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.  NSP-Minnesota’s electric generating facilities are likely to be subject to regulation under climate change policies introduced at either the state or federal level within the next few years.  Numerous states have proposed or implemented clean energy policies, such as renewable energy portfolio standards or DSM programs, in part designed to reduce the emissions of GHGs.  Congress and federal policy makers are considering climate change legislation and a variety of national climate change policies and regulations.  NSP-Minnesota is advocating with state and federal policy makers for climate change and clean energy policies that will result in significant long-term reduction in GHG emissions, develop low-emitting technologies and secure, cost-effective energy supplies for our customers and our nation.

While NSP-Minnesota is not currently subject to state or federal limits on its GHG emissions, NSP-Minnesota has undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions.  These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects.  Although the impact of climate change policy on NSP-Minnesota will depend on the specifics of state and federal policies, legislation and regulation, NSP-Minnesota believes that, based on prior state commission practice, NSP-Minnesota would be granted the authority to recover the cost of these initiatives through rates.

Utility Restructuring and Retail Competition — The FERC has continued with its efforts to promote more competitive wholesale markets through open-access transmission and other means.  As a consequence, NSP-Minnesota can purchase from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ to serve their native load.  In 2008, the FERC approved a MISO proposal to begin operation of a regional Ancillary Services Market (ASM) in January 2009.  NSP-Minnesota supports the continued development of wholesale competition and non-discriminatory wholesale open-access transmission services.  NSP-Minnesota received MPUC approval in 2008 to construct three new 115 KV transmission lines in 2009 to deliver additional wind generation even if NSP-Minnesota does not purchase the generation.

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The retail electric business faces competition as industrial and large commercial customers have some ability to own or operate facilities to generate their own electricity.  In addition, customers may have the option of substituting other fuels, such as natural gas or steam/chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region.  While NSP-Minnesota faces these challenges, it believes its rates are competitive with currently available alternatives.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states.  The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, property transfers, mergers and transactions between NSP-Minnesota and its affiliates.  In addition, the MPUC reviews and approves NSP-Minnesota’s electric resource plans for meeting customers’ future energy needs.  The MPUC also certifies the need for generating plants greater than 50 MW and transmission lines greater than 100 KV.

No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC.  The NDPSC and SDPUC have regulatory authority over generating and transmission facilities, and the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale and the transmission of electricity in interstate commerce.  NSP-Minnesota has received authorization from the FERC to make wholesale electric sales at market-based prices (see market-based rate authority discussion) and is a transmission-owner member of the MISO RTO.

Fuel, Purchased Energy and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail electric rate schedules in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred cost of fuel, fuel related items and purchased energy.  NSP-Minnesota is permitted to recover these costs through FCA mechanisms approved by the regulators in each jurisdiction.

The FCAs allow NSP-Minnesota to bill customers for the cost of fuel and fuel related costs used to generate electricity at its plants and energy purchased from other suppliers.  In general, capacity costs are not recovered through the FCA.  In December 2006, the MPUC authorized FCA recovery of all MISO Day 2 charges, except certain administrative charges, which NSP-Minnesota partially recovered in base rates and partially deferred for future recovery in its 2009 Minnesota electric rate case.  The SDPUC and NDPSC have authorized FCA recovery of MISO Day 2 charges.  In 2008, NSP-Minnesota requested that the MPUC, NDPSC and SDPUC allow FCA treatment of all MISO ASM charges and revenues effective with the start of the ASM on Jan. 6, 2009.  The SDPUC approved the request on Feb. 12, 2009.  The NDPSC has concluded that the recovery was addressed and permitted through the recent rate case settlement.  NSP-Minnesota heard the matter on Feb. 26, 2009.  NSP-Minnesota’s electric wholesale customers also have a FCA provision in their contracts.

NSP-Minnesota is required by Minnesota law to spend a minimum of 2 percent of Minnesota electric revenue on conservation improvement programs.  These costs are recovered through an annual cost recovery mechanism for electric conservation and energy management program expenditures.  NSP-Minnesota is required to request a new cost recovery level annually.  While this law will change to a savings-based requirement beginning in 2010, the costs of providing qualified conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.

MERP Rider Regulation — In December 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant.  These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW.  The first MERP project at the A. S. King plant went into service in July 2007.  The second project at the High Bridge plant went into service in May 2008.  The remaining project at the Riverside facility is expected to begin operations in 2009.  The MPUC approved a rate rider to recover prudent costs of the projects from Minnesota customers beginning Jan. 1, 2006, including a rate of return on the construction work in progress.

The MPUC approval has a sliding ROE scale with a range of 9.87 to 11.47 percent, based on actual construction cost compared with a target level of construction costs (based on an equity ratio of 48.5 percent and debt of 51.5 percent) to incentivize NSP-Minnesota to control construction costs.  At Dec. 31, 2008, the estimated ROE was 10.71 percent, based on construction progress to date.

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Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2009, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2006	2007	2008	2009 Forecast
NSP System	9,859	9,427	8,697	9,662

The peak demand for the NSP System typically occurs in the summer.  The 2008 system peak demand for the NSP System occurred on July 29, 2008.

Energy Sources and Related Transmission Initiatives

NSP-Minnesota expects to use existing power plants, power purchases, DSM options, new generation facilities and expansion of existing power plants to meet its system capacity requirements.

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and independent power producers.  Capacity is the measure of the rate at which a particular generating source produces electricity.  Energy is a measure of the amount of electricity produced from a particular generating source over a period of time.  Long-term purchase power contracts typically require a periodic payment to secure the capacity from a particular generating source and a charge for the associated energy actually purchased from such generating source.

On behalf of the NSP System, NSP-Minnesota also makes short-term purchases to replace generation from company-owned units that are unavailable due to maintenance and unplanned outages, to comply with minimum availability requirements, to obtain energy at a lower cost than that which could be produced by other resource options, including company-owned generation and/or long-term purchase power contracts and for various other operating requirements.

Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contractual arrangements with MISO and regional transmission service providers to deliver power and energy to the NSP System for native load customers, which are retail and wholesale load obligations with terms of more than one year.

Excelsior Energy — In December 2005, Excelsior, an independent energy developer, filed a power purchase agreement with the MPUC seeking a declaration that NSP-Minnesota be compelled to enter into an agreement to purchase the output from two integrated gas combined cycle (IGCC) plants to be located in northern Minnesota as part of the Mesaba Energy Project.  Excelsior filed this petition making claims pursuant to Minnesota statutes relating to an Innovative Energy Project and Clean Energy Technology.  NSP-Minnesota opposed the petition.

The MPUC referred this matter to a contested case hearing before an ALJ to act on Excelsior’s petition.  The contested case proceeding considered a 600 MW unit in Phase 1 and a second 600 MW unit in Phase 2 of the Mesaba Energy Project.

The MPUC issued its order for phase 1 of the hearing on Aug. 30, 2007.  In it, the MPUC found among other things, that Excelsior and NSP-Minnesota should resume negotiations toward an acceptable purchase power agreement, with assistance from the Minnesota Department of Commerce (MDOC) and the guidance provided by the order.

On Sept. 24, 2008, the MPUC denied Excelsior Energy’s Phase 2 request to approve a power purchase agreement related to its proposed second 600 MW IGCC generating facility.  The MPUC also set a May 1, 2009 deadline for Phase 1 of the proceeding in which it had previously ordered negotiations.  On Oct. 14, 2008, Excelsior sought rehearing of the MPUC’s Sept. 24, 2008 order.  On Dec. 9, 2008, the MPUC held further action in abeyance until after the May 1, 2009 deadline.

GHG Emissions — The 2007 Minnesota legislature adopted the goal to reduce statewide GHG emissions across all sectors to a level at least 15 percent below 2005 levels by 2015, to a level at least 30 percent below 2005 levels by 2025, and to a level at least 80 percent below 2005 levels by 2050.

The legislation also prohibits the construction within Minnesota of a new large energy facility, the import or commitment to import from outside Minnesota power from a new large energy facility, or entering into a new long-term power purchase agreement that would increase statewide power sector CO2 emissions.  The statute does not impose limitations on CO2 or

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other GHG emissions on NSP-Minnesota and provides for certain exemptions.  On Feb. 1, 2008, the MDOC submitted to the legislature a climate change action plan that proposes certain changes to meet the requirements of this section.

Renewable Energy Standard (RES) — The 2007 Minnesota legislature adopted a RES statute requiring that 30 percent of NSP-Minnesota’s energy requirements by 2020 come from qualifying renewable sources, primarily wind energy.  Costs associated with complying with the standard are recoverable through automatic recovery mechanisms.

NSP-Minnesota has filed with the MPUC a renewable energy plan for adding wind resources.  This plan seeks to achieve balance in the wind portfolio, with roughly half of new resources being owned by NSP-Minnesota and achieving roughly proportionate shares between community-based energy developments, other power purchase agreements and utility projects.

Conservation and DSM Legislation — The 2007 Minnesota legislature adopted a statute establishing a statewide goal to reduce energy demand by 1.5 percent per year and fossil fuel use by 15 percent.  The bill requires utilities to propose conservation and DSM programs that achieve at least 1.0 percent per year reduction in energy demand, subject to limitations regarding excessive costs for customers, reliability or other negative consequences.  The statute also allows utilities to fund internal infrastructure changes that will contribute to lower energy use and provides for cost recovery outside a rate case for such projects.

2008 Minnesota Legislative Session — The 2008 Minnesota legislature considered and adopted several measures related to energy policy and regulation, including:

·Encouraging Minnesota’s participation in the Midwest Governors’ Association’s GHG accord and commissioning of an economic study of the potential impacts of a carbon cap-and-trade program;

·Modifying the existing TCR mechanism to allow for recovery of costs associated with MISO charges for regional transmission expansion;

·Providing for recovery via a rate rider mechanism of certain energy storage projects associated with renewable energy projects; and

·Providing for a streamlined approval process for wind and solar projects needed to comply with Minnesota’s RES.

The legislature considered, but did not adopt, increased taxes on utility property.

NSP System Resource Plan — In December 2007, NSP-Minnesota filed its 2007 resource plan with the MPUC.  The plan incorporates the actions needed to comply with expansive new legislation regarding GHG emissions control, renewable energy procurement and DSM adopted by the 2007 Minnesota legislature.  Due to the expansion of wind generation procurement and DSM obligations, the plan indicates that the type of incremental resources has changed from prior plans.  Key provisions of the plan include the following:

·Adding 2,600 MW of wind generation resources to comply with our RES of 30 percent renewable energy by 2020.

·Increases in DSM of approximately 30 percent energy savings and 50 percent demand savings.

·Seek license renewals for Prairie Island’s two units through 2033 and 2034, respectively, and expand capacity at Prairie Island by 160 MW and Monticello by 71 MW.

·Request approval to make environmental and capacity upgrades at Sherburne County (Sherco).  The environmental upgrades would result in a significant reduction in overall SO2, NOx and mercury emissions from the facility.

·Negotiate and seek approval of purchases from Manitoba Hydro Electric Board (Manitoba Hydro) for 375 MW of intermediate and 350 MW of peaking resources beginning in 2015.

·Incremental peaking and intermediate generation needs of 2,300 MW.

·Carbon emission reductions of 22 percent below 2005 levels by 2020.

In June 2008, intervenors filed comments on this plan.  The Minnesota Office of Energy Security (OES) recommended approval, subject to further expansion of DSM goals.  Environmental intervenors recommended expanded DSM goals and expressed concerns regarding carbon management with the proposed expansion of certain coal resources.  Excelsior Energy recommended inclusion of its proposed project in the plan.  The Prairie Island Community expressed health and safety concerns regarding nuclear resources.  The Minnesota Chamber of Commerce expressed interest in cost and rate management.  NSP-Minnesota filed reply comments in September 2008 providing updated information, including a revised forecast.  As discussed below it also withdrew its request for upgrades at Sherco Units 1 and 2.  The MPUC is expected to act on the plan in the first half 2009.

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Additional Base Load Capacity Projects for Sherco, Monticello and Prairie Island — The MPUC order in the 2004 NSP-Minnesota resource plan indicated that additional capacity from the Sherco, Monticello, and Prairie Island plants would be cost-effective and should be pursued.  The disclosure regarding the Monticello and Prairie Island plans is included below under “Nuclear Power Operations and Waste Disposal.”

In December 2007, NSP-Minnesota filed a plan for major pollution control and efficiency improvements at Sherco Units 1 and 2 with the MPUC.  The plan proposed conversion of the pollution control systems at the plant from wet scrubber precipitator technology to dry spray absorber/ baghouse equipment as well as efficiency improvements that would increase the production capacity of the plant by 70 MW.  The total cost of the proposed plan was estimated at $1 billion.  In November 2008, NSP-Minnesota filed a request with the MPUC to withdraw the plan to reevaluate alternatives, due to significant changes in the national economy, lower forecast of energy consumption, and new information concerning an emerging technology that may be more cost effective.  The MPUC granted the withdrawal request on Dec. 9, 2008.

Wind Generation — In December 2008, the first NSP-Minnesota owned wind generation plant, the 100 MW Grand Meadow wind farm, went into service.  The project was developed through a build-own-transfer arrangement with a large wind energy developer (enXco) at a cost of approximately $210 million.  NSP-Minnesota plans to invest approximately $900 million over three years for a 201 MW project in southwestern Minnesota, called the Nobles Wind Project, and a 150 MW project in southeastern North Dakota, called the Merricourt Wind Project.  These projects are expected to be operational by the end of 2010 and 2011, respectively.  On Dec. 3, 2008, NSP-Minnesota filed petitions with the MPUC and the NDPSC seeking the required regulatory approvals for the two wind powered generating facilities.  See additional discussion of wind generation in Item 7— Management’s Discussion and Analysis of Financial Condition and Results of Operations.

NSP-Minnesota Transmission Certificates of Need — In August 2007, NSP-Minnesota and Great River Energy (on behalf of eight other regional transmission providers) filed a certificate of need application, for three 345 KV transmission lines, as part of the CapX 2020 project.  The project to build the three lines includes construction of approximately 600 miles of new facilities at a cost of approximately $1.7 billion, with construction to be completed in phases.  The cost of the project to NSP-Minnesota and NSP-Wisconsin is estimated to be approximately $900 million.  These cost estimates will be revised after the regulatory process is completed.  Evidentiary hearings were completed in September 2008.  The OES recommended an increase in capacity for the Fargo, N. D. project.  An environmental coalition supported the projects subject to conditions for wind purchases or commitments for the transmission capacity, while two other intervenors opposed the proposal.  The applicants filed rebuttal testimony recommending the modification of all three projects to be constructed as double circuit compatible with the first circuit strung during initial construction and the second circuit strung as needed.  NSP-Minnesota expects the ALJ to issue a report and recommendation in the first quarter of 2009.  The MPUC is expected to make a final decision in 2009 after receipt of the ALJ report.

As part of CapX 2020, Otter Tail Power Company, Minnesota Power and Minnkota Power Cooperative (on behalf of themselves and NSP-Minnesota and Great River Energy) filed a certificate of need application in March 2008 for a 230 KV transmission line between Bemidji and Grand Rapids, Minn.  A route application for this project was filed in June 2008.  The need application is uncontested; route hearings are expected to be conducted in late 2009, and an MPUC decision is anticipated by the second quarter of 2010.  The Bemidji-Grand Rapids line is expected to entail construction of approximately 68 miles of new facilities at a cost of $100 million, with construction to be completed by end of 2011.  The estimated cost to NSP-Minnesota is approximately $26 million.

In the second quarter of 2009, NSP-Minnesota plans to file a certificate of need application with the MPUC for two 161 KV transmission lines in the Rochester, Minn. area to support ongoing development of wind powered generation in southeastern Minnesota.  The proposal consists of an approximately 15 mile long, 161 KV transmission line north of Rochester, and an approximately 30 mile long, 161 KV transmission line southeast of Rochester.  The project’s estimated cost is $30 million.  An MPUC decision is anticipated late in 2009.

FCA Investigation — In 2003, the MPUC opened an investigation to consider the continuing usefulness of the FCAs for electric utilities in Minnesota.  There was no further activity until the MPUC issued a notice for comments on April 5, 2007, as to whether to continue the statewide investigation.

Pursuant to the notice, utilities in Minnesota, the MDOC and the Minnesota Office of Attorney General (MOAG) filed comments.  The utilities generally argued the 2003 investigation could be closed, with remaining issues addressed in the separate investigation initiated by the Dec. 20, 2006 order in the MISO Day 2 cost recovery docket.  The MDOC filed comments seeking to continue the investigations.  In response, the utilities filed additional comments on Sept. 28, 2007, that indicated a willingness to continue with the investigation and provide more information to both regulators and customers

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regarding fuel and purchased power costs, plant outages and other factors affecting fuel clause levels.  Continued discussions among utilities, the MDOC, MOAG and business customers regarding appropriate FCA reporting detail and provision of additional information to customers is on going.

Mercury Reduction and Emissions Reduction Filings — In December 2007, NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercury emissions at the Sherco Unit 3 and A. S. King plants.  Currently, the estimated project costs are approximately $8.5 million.  The MPUC has approved the mercury control plans.  Implementation will begin in 2009.  NSP-Minnesota plans to seek cost recovery of mercury control investments through an automatic rate adjustment mechanism (rate rider) filing later in 2009.  As discussed above, NSP-Minnesota is reexamining its plans for emission controls at Sherco Units 1 and 2 and anticipates submitting an alternative mercury control plan with the MPUC in 2009.

Nuclear Power Operations and Waste Disposal — NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the Prairie Island plant, which has two units.  See additional discussion regarding the nuclear generating plants in Note 15 to the consolidated financial statements.

Nuclear power plant operation produces gaseous, liquid and solid radioactive wastes.  The discharge and handling of such wastes are controlled by federal regulation.  High-level radioactive wastes primarily include used nuclear fuel.  Low-level radioactive waste (LLW) consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in the plant.

LLW Disposal — Federal law places responsibility on each state for disposal of LLW generated within its borders.  LLW from NSP-Minnesota’s Monticello and Prairie Island nuclear plants is currently disposed at the Barnwell facility located in South Carolina (all classes of LLW) and at the Clive facility located in Utah (class A LLW only).  NSP-Minnesota had an annual contract with Barnwell that expired on June 30, 2008, but is also able to utilize the Clive facility through various LLW processors.  NSP-Minnesota has storage capacity available on-site at Prairie Island and Monticello that would allow both plants to continue to operate until the end of their current licensed lives, if off-site LLW disposal facilities were not available to NSP-Minnesota.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to dispose of, or permanently store, domestic spent nuclear fuel and other high-level radioactive wastes.  The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management.  This includes the siting, licensing, construction and operation of a repository for domestically produced spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility.  To date, the DOE has not accepted any of NSP-Minnesota’s spent nuclear fuel.  See Item 3 — Legal Proceedings and Note 15 to the consolidated financial statements for further discussion of this matter.

NSP-Minnesota has on-site storage for spent nuclear fuel at its Monticello and Prairie Island nuclear plants.  At the following dates casks for storage were either authorized or casks were loaded and stored:

·In 1993, the Prairie Island plant was licensed by the federal NRC to store up to 48 casks of spent fuel at the plant.

·In 1994, the Minnesota legislature adopted a limit on dry cask storage of 17 casks.

·In 2003, the Minnesota legislature enacted revised legislation that will allow NSP-Minnesota to continue to operate the facility and store spent fuel there until its current licenses with the NRC expire in 2013 and 2014.  It is estimated that operation through the end of the current license will require 12 additional storage casks to be stored at Prairie Island, for a total of 29 casks.

·In October 2006, the MPUC authorized an on-site storage facility and 30 casks at Monticello, which will allow the plant to operate to 2030.  The MPUC decision became effective June 1, 2007.

·As of Dec. 31, 2008, there were 24 casks loaded and stored at the Prairie Island plant and 10 casks loaded and stored at the Monticello plant.

See Note 15 in the consolidated financial statements for further discussion of the matter.

PFS — NSP-Minnesota is part of a consortium of private parties working to establish a private facility for interim storage of spent nuclear fuel.  In 1997, PFS filed a license application with the NRC for a temporary storage site for spent nuclear fuel on the Skull Valley Indian Reservation in Utah.  On Feb. 28, 2006, the NRC commissioners issued the license for PFS.  In December 2005, the U.S. Supreme Court denied Utah’s petition for a writ of certiorari to hear an appeal of a lower court’s ruling on a series of state statutes aimed at blocking the storage and transportation of spent fuel to PFS.  Also in December 2005, NSP-Minnesota indicated that it would hold in abeyance future investments in the construction of PFS as

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long as there is apparent and continuing progress in federally sponsored initiatives for storage, reuse, and/or disposal for the nation’s spent nuclear fuel.  In September 2006, the Department of the Interior issued two findings: (1) that it would not grant the leases for rail or intermodal sites and (2) that it was revoking its previous conditional approval of the site lease between PFS and the Skull Valley Indian tribe.  The stated reasons were principally lack of progress at Yucca Mountain and lack of Bureau of Indian Affairs staff to monitor this activity.  Both findings are expected to be appealed.

Nuclear Plant Power Uprates and Life Extension — NSP-Minnesota is pursuing life extensions and capacity increases for all three of its nuclear units that will total approximately 230 MW, to be implemented, if approved, between 2009 and 2015.  The life extension and a capacity increase for Prairie Island Unit 2 is contingent on replacement of the original steam generators, currently planned for replacement during the refueling outage in 2013.  Capital investments for life cycle management and power uprate activities through 2008 have totaled over approximately $125 million.  For the years 2009 through 2015, spending is estimated at over $1.0 billion.  See additional discussion in Capital Requirements in Item 7 —  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

NSP-Minnesota has filed two applications for certificates of need related to its nuclear generating facilities to obtain approval for these projects.  The first addresses approximately 71 MW of power uprates at the Monticello plant.  The MPUC approved the Monticello power uprate Certificate of Need in December 2008.  NSP-Minnesota re-submitted its NRC application for the Monticello plant extended power uprate in November 2008, and the NRC’s Sufficiency review of the license amendment re-submittal was completed in December 2008.  Although this delays the extended power uprate process slightly, NSP-Minnesota does not anticipate a substantial delay in the project at this time.  The operating life of the Monticello nuclear plant has already been extended through 2030.

The second application addresses both life extension and approximately 160 MW in power uprates at Prairie Island Units 1 and 2.  In July 2008, the MPUC determined that the application was complete and referred it to an ALJ for contested case hearing.  The Prairie Island Community has indicated its interest in the power uprate portion of the case and has expressed interest in revisiting its 2003 settlement with NSP-Minnesota, in which it agreed that certain concerns it may have regarding Prairie Island life extension would be addressed in the federal relicensing process.

In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years, until 2033 and 2034, respectively.  The Prairie Island Indian Community (PIIC) filed contentions in the NRC’s license renewal proceeding in August 2008.  The PIIC request was referred to an Atomic Safety and Licensing Board (ASLB) for review.  The ASLB has granted the PIIC hearing request and has admitted 7 of the 11 contentions filed.  The resulting adjudicatory process and hearings are expected to add approximately 8 months onto the NRC’s standard 22-month review schedule.  Therefore, the NRC is not expected to make a decision until late 2010.  An application for a Certificate of Need to expand the spent fuel storage capacity at Prairie Island to support 20 additional years of operation was filed with the MPUC in May 2008.  It is expected that the MPUC will act in late 2009, which would result in the MPUC decision being stayed during the 2010 session of the Minnesota legislature before going into effect.

NMC — On Sept. 28, 2007, NSP-Minnesota obtained 100 percent ownership in NMC.  Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota’s consolidated financial statements from the Sept. 28, 2007 transaction date.  NSP-Minnesota has reintegrated its nuclear operations into its generation operations.  The application to the NRC to transfer the nuclear operating licenses from NMC to NSP-Minnesota was completed on Sept. 22, 2008.

For further discussion of nuclear obligations, see Note 15 to the consolidated financial statements.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

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													Weighted
NSP System	Coal*				Nuclear				Natural Gas				Average Fuel
Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Cost
2008	$	1.73	58	%	$	0.56	39	%	$	10.09	3	%	$	1.55
2007	1.56		57		0.51		38		7.60		4		1.47
2006	1.12		59		0.46		38		7.28		3		1.08

*Includes refuse-derived fuel and wood

See additional discussion of fuel supply and costs under Item 1A — Risks Associated with Our Business.

Fuel Sources

Coal — Coal inventory levels may vary widely among plants.  The NSP System normally maintains approximately 39 days of coal inventory at each plant site.  Coal supply inventories at Dec. 31, 2008 and 2007, were approximately 49 and 47 days usage, based on the maximum burn rate for all of NSP-Minnesota’s coal-fired plants.  NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under long-term contracts with suppliers operating in Wyoming and Montana.  Estimated coal requirements at NSP-Minnesota’s and NSP-Wisconsin’s major coal-fired generating plants were approximately 11.0 and 12.4 million tons per year at Dec. 31, 2008 and 2007, respectively.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 100 percent of their coal requirements in 2009, 65 percent of their coal requirements in 2010 and 36 percent of their coal requirements in 2011.  Any remaining requirements will be filled through a request for proposal (RFP) process according to the fuel supply operations procurement strategy.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2009, 100 percent of their coal requirements in 2010 and 28 percent of their coal requirements 2011.  Coal delivery may be subject to short-term interruptions or reductions due to operation of mines, transportation problems, weather and availability of equipment.

Nuclear — To operate NSP-Minnesota’s nuclear generating plants, NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication.  The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium, conversion and enrichment with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions.

·Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2009, approximately 68 percent of the requirements for 2010, 80 percent of the requirements for 2011 through 2013, 47 percent of the requirements for 2014 through 2017, with no arrangements for 2018 and beyond.  Contracts for additional uranium concentrate supplies are currently in various stages of negotiations that are expected to provide a portion of the requirements through 2012.

·Current contracts for conversion services cover 100 percent of the requirements through 2011 and approximately 56 percent of the requirements from 2012 through 2015, with no arrangements for 2016 and beyond.

·Current enrichment services contracts cover 100 percent of 2009 through 2012 requirements and approximately 60 percent of 2013 requirements.  A contract for additional enrichment services is being negotiated to provide the remainder of coverage for open requirements in 2013.  There is currently no coverage for 2014 and beyond.  Offers for enrichment services for supply contracts for 2014 and beyond are being reviewed.

·The fuel fabrication contract for Monticello was extended during 2007 to cover one additional reload in 2011.  Request for proposals from the fuel fabrication vendors for additional supply for Monticello were distributed.  Offers from fuel fabrication vendors are being reviewed with plans to enter into a contract with one of the vendors in 2009.  Prairie Island’s fuel fabrication is 100 percent committed to at least 2015.

NSP-Minnesota expects sufficient uranium, conversion and enrichment to be available for the total fuel requirements of its nuclear generating plants.  Contracts for additional uranium are currently being negotiated that would provide additional supply requirements through 2012.  Some exposure to price volatility will remain, due to index-based pricing structures of the contracts.

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Natural Gas — The NSP System uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers.  Natural gas supplies and associated transportation and storage services for power plants are procured under contracts with various terms to provide an adequate supply of fuel.  The supply, transportation and storage contracts expire in various years from 2009 to 2028.  Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2008, NSP-Minnesota’s commitments related to supply contracts was $89 million and commitments related to transportation and storage contracts were approximately $652 million.  The NSP System has limited on-site fuel oil storage facilities and relies on the spot market for incremental supplies, if needed.

Wholesale Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products.  NSP-Minnesota uses physical and financial instruments to reduce commodity price and credit risk and hedge supplies and purchases.  See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of NSP-Minnesota.  State and local agencies have jurisdiction over many of NSP-Minnesota’s activities, including regulation of retail rates and environmental matters.  In addition to the matters discussed below, see Note 13 to the consolidated financial statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act repealed PUHCA effective Feb. 8, 2006 and required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act.  Since August 2005, the FERC has completed a number of rulemaking proceedings to modify its regulations on a number of subjects, including:

·Adopting regulations requiring NERC to establish mandatory electric reliability standards; and

·Certifying approximately 120 NERC reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance.

While NSP-Minnesota cannot predict the ultimate impact the new regulations will have on its operations or financial results, NSP-Minnesota is taking actions that are intended to comply with and implement these new rules and regulations as they become effective.

Electric Reliability Standards Matters — The electric production and transmission system of NSP-Minnesota is managed as an integrated system, jointly referred to as the NSP System.  On Sept. 18, 2007, portions of the NSP System and transmission systems west and north of the NSP System briefly islanded from the rest of the Eastern Interconnection, as a result of a series of transmission line outages.  The initial transmission line outage appears to have occurred on the NSP-Minnesota transmission system due to a failure of a 345 KV conductor during severe weather, and approximately 6,000 NSP-Wisconsin customers temporarily lost power.  The Midwest Reliability Organization (MRO), the NERC regional entity responsible for oversight of electric system reliability in the upper Midwest, including the NSP System, initiated an independent incident analysis.  In addition, NERC initiated a compliance investigation to determine if violations of mandatory NERC reliability standards contributed to the event.  Xcel Energy is cooperating with the MRO incident analysis and NERC compliance investigation.

In April 2008, a self-report was filed with MRO indicating that certain tests of generation station batteries had not been completed in accordance with Xcel Energy’s adopted maintenance plan for generation station relays and batteries.  Xcel Energy has received preliminary information from the MRO indicating that financial penalties are likely to be assessed against NSP-Minnesota and NSP-Wisconsin in conjunction with this self-report, though the amount of those penalties is not expected to be material.

In June 2008, PSCo was subject to an audit of its compliance with NERC and regional reliability standards by Western Electricity Coordinating Council , the NERC regional entity for the PSCo system.  In response to information identified during the audit, Xcel Energy conducted a comprehensive review of the maintenance records for all relay devices on the NSP-Minnesota and NSP-Wisconsin transmission systems.  That review found NSP-Minnesota and NSP-Wisconsin did not

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have documentation demonstrating that all relay devices on those systems had been maintained on the schedule in Xcel Energy’s adopted maintenance plan.  In June 2008, the NSP System filed a self-report regarding the maintenance plan violations with the MRO.  The NSP System supplemented the self-report on Feb. 17, 2009.

In September 2008, as a result of a review of Xcel Energy’s procedures implementing certain NERC critical infrastructure protection standards applicable to control centers effective July 1, 2008, the NSP System filed a self-report with the MRO disclosing certain deficiencies in requirements applicable to access to critical infrastructure assets for the period July to September 2008.  The NSP System filed a mitigation plan with the MRO within 30 days of the self-report discussing how the deficiencies were corrected.  The MRO notified the NSP System it will not impose a financial penalty related to the self report.

Xcel Energy is uncertain if the NERC investigation regarding the Sept. 18, 2007 NSP System event or the self-reports of reliability standards violations will result in financial penalties being imposed on NSP-Minnesota and NSP-Wisconsin.  If so, the penalties are not expected to be material.

Electric Transmission Rate Regulation — The FERC regulates the rates charged and terms and conditions for electric transmission services.  FERC policy encourages utilities to turn over the functional control over their electric transmission assets for the sale of electric transmission services to an RTO.  NSP-Minnesota and NSP-Wisconsin are members of the MISO RTO.  Each RTO separately files regional transmission tariff rates for approval by the FERC.  All members within that RTO are then subjected to those rates.

In February 2007, the FERC issued final rules (Order No. 890) adopting revisions to its open access transmission service rules.  In December 2007, the FERC issued an order on rehearing (Order No. 890-A) making certain modifications to Order No. 890, effective in March 2008.  In June 2008, the FERC issued a further order on rehearing (Order No. 890-B) making certain additional modifications to Order Nos. 890 and 890-A effective in September 2008.  Xcel Energy submitted its compliance filing to Order No. 890-B in September 2009.  The various compliance filings are pending FERC action.

Centralized Regional Wholesale Markets — The FERC rules allow RTOs to operate centralized regional wholesale energy markets.  In April 2005, MISO began operation of a “Day 2” regional day-ahead and real time wholesale energy market.  MISO uses security constrained regional economic dispatch and congestion management using locational marginal pricing (LMP) and FTRs.  The Day 2 market is designed to provide more efficient generation dispatch over the 15 state MISO region, including the NSP System.

In September 2007, MISO filed for FERC approval to establish a centralized regional wholesale ASM in 2008.  The ASM is intended to provide further efficiencies in generation dispatch by allowing for regional regulation response and contingency reserve services through a bid-based market mechanism co-optimized with the Day 2 energy market.  In February 2008, the FERC issued an order conditionally approving the ASM tariff, but requiring certain changes.  In December 2008, the FERC issued orders approving the MISO filings necessary for MISO to start the ASM.  MISO began ASM operations in January 2009.  To date, the ASM has generally functioned as anticipated.

In December 2007, MISO filed proposed changes to the TEMT (called Module E) to establish a long-term resource adequacy proposal.  The proposal contains mandatory requirements for any market participant serving load in the MISO region, including the NSP System, to have and maintain access to sufficient resources to meet adequacy standards.  The resources used to meet a resource adequacy requirement may include self-generation capacity, firm purchased power and demand response capability.

Under the Module E proposal, MISO will establish a Planning Reserve Margin for each Load-Serving Entity (LSE).  The MISO resource adequacy tariff would replace the NSP System current planning reserve obligations.  In March 2008, the FERC issued an order approving the Module E tariff.  Various parties requested rehearing of the FERC order.  MISO is expected to start Module E on March 1, 2009.

Market Based Rate Rules — In June 2007, the FERC issued a final order governing its market-based rate authorizations to electric utilities.  The FERC reemphasized its commitment to market-based pricing, but is revising the tests it uses to assess whether a utility has market power and has emphasized that it intends to exercise greater oversight where it has market-based rate authorizations.  NSP-Minnesota has been granted market-based rate authority and will be subject to the new rule.

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On Dec. 22, 2008, the NSP System submitted their Triennial Market Power Analysis to the FERC to support their market-based rate authority.  Applying the FERC’s required tests, the Market Power Analysis submitted by the NSP System demonstrates that they have neither horizontal market power nor vertical market power in the relevant geographic market.  Consequently, the NSP System has requested that the FERC permit them to retain their market-based rate authority.

Affiliate Transaction Rules — On Feb. 21, 2008, the FERC issued Order No. 707, which amended the FERC’s regulations to codify restrictions on affiliate transactions between franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities, and their market-regulated power sales affiliates or non-utility affiliates.  The Xcel Energy utility subsidiaries are subject to the new rules.  The rules apply historic SEC “at cost” pricing standards to transactions between service companies of utility holding company systems and their FERC jurisdictional public utility affiliates.  In September 2008, the National Rural Electric Cooperative Association and the American Public Power Association filed a petition for review of Order No. 707 with the U.S. Court of Appeals for the District of Columbia.  The appeal is pending.

Electric Operating Statistics

	Year Ended Dec. 31,
	2008			2007			2006
Electric sales (millions of Kwh)
Residential	10,099			10,534			10,223
Commercial and industrial	25,847			25,844			25,420
Public authorities and other	260			275			280
Total retail	36,206			36,653			35,923
Sales for resale	3,692			4,073			5,435
Total energy sold	39,898			40,726			41,358
Number of customers at end of period
Residential	1,227,889			1,218,340			1,206,278
Commercial and industrial	148,060			146,487			144,315
Public authorities and other	6,067			6,072			5,998
Total retail	1,382,016			1,370,899			1,356,591
Wholesale	31			31			35
Total customers	1,382,047			1,370,930			1,356,626
Electric revenues (thousands of dollars)
Residential	$	1,018,810		$	1,015,315		$	929,276
Commercial and industrial	1,853,451			1,774,027			1,665,004
Public authorities and other	31,837			31,446			30,898
Total retail	2,904,098			2,820,788			2,625,178
Wholesale	180,618			198,248			227,000
Interchange revenues from NSP-Wisconsin	390,143			372,215			322,733
Other electric revenues	109,250			85,423			90,460
Total electric revenues	$	3,584,109		$	3,476,674		$	3,265,371
Kwh sales per retail customer	26,198			26,737			26,480
Revenue per retail customer	$	2,101		$	2,058		$	1,935
Residential revenue per Kwh	10.09		¢	9.64		¢	9.09		¢
Commercial and industrial revenue per Kwh	7.17			6.86			6.55
Wholesale revenue per Kwh	4.89			4.87			4.18

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NATURAL GAS UTILITY OPERATIONS

The most significant recent developments in the natural gas operations of NSP-Minnesota are continued volatility in natural gas market prices and the continued trend of declining use per customer by residential customers as a result of improved building construction technologies, higher appliance efficiencies and conservation.  From 1998 to 2008, average annual sales to the typical residential customer declined from 111 MMBtu per year to 88 MMBtu per year on a weather-normalized basis.  Although recent wholesale price increases do not directly affect earnings because of natural gas cost recovery mechanisms, high prices can encourage further efficiency efforts by customers.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC and the NDPSC within their respective states.  The MPUC has regulatory authority over aspects of NSP-Minnesota’s financial activities, including security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates.  In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future energy needs.

Purchased Gas and Conservation Cost Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas.  The annual difference between the natural gas costs collected through PGA rates and the actual natural gas costs are collected or refunded over the subsequent 12-month period.  The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

NSP-Minnesota is required by Minnesota law to spend a minimum of 0.5 percent of Minnesota natural gas revenue on conservation improvement programs.  These costs are recovered through an annual cost recovery mechanism for natural gas conservation and energy management program expenditures.  This law will change to a savings-based requirement beginning in 2010, and the costs of conservation improvement programs will continue to be recoverable through a rate adjustment mechanism.

For a further discussion of rate and regulatory matters see Note 13 to the consolidated financial statements.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply).  The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 700,323 MMBtu for 2008, which occurred on Dec. 16, 2008.

NSP-Minnesota purchases natural gas from independent suppliers.  These purchases are generally priced based on market indices that reflect current prices.  The natural gas is delivered under transportation agreements with interstate pipelines.  These agreements provide for firm deliverable pipeline capacity of 573,668 MMBtu/day.  In addition, NSP-Minnesota has contracted with providers of underground natural gas storage services.  These storage agreements provide storage for approximately 26 percent of winter natural gas requirements and 32 percent of peak day, firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.13 Bcf equivalent and three propane-air plants with a storage capacity of 1.4 Bcf equivalent to help meet its peak requirements.  These peak-shaving facilities have production capacity equivalent to 250,300 MMBtu of natural gas per day, or approximately 33 percent of peak day firm requirements.  LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another.  The 2007-2008 and 2008-2009 entitlement levels are pending MPUC action.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates.  In addition, NSP-Minnesota

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conducts natural gas price hedging activity that has been approved by the MPUC.  This diversification involves numerous domestic and Canadian supply sources with varied contract lengths.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Minnesota’s regulated retail natural gas distribution business:

2008	$	8.41
2007	7.67
2006	8.32

The cost of natural gas supply, transportation service and storage service is recovered through the PGA cost recovery mechanism.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2009 through 2028.

NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.  At Dec. 31, 2008, NSP-Minnesota was committed to approximately $688 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 27 domestic and Canadian suppliers.  This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

Natural Gas Operating Statistics

	Year Ended Dec. 31,
	2008		2007		2006
Natural gas deliveries (thousands of MMBtu)
Residential	41,589		38,024		33,896
Commercial and industrial	42,640		40,184		35,231
Other	529		2,276		1,370
Total retail	84,758		80,484		70,497
Transportation and other	12,484		8,528		8,727
Total deliveries	97,242		89,012		79,224
Number of customers at end of period
Residential	434,987		430,048		426,479
Commercial and industrial	40,174		39,570		39,056
Total retail	475,161		469,618		465,535
Transportation and other	15		14		14
Total customers	475,176		469,632		465,549
Natural gas revenues (thousands of dollars)
Residential	$	467,751	$	413,790	$	394,204
Commercial and industrial	413,871		350,640		335,392
Total retail	881,622		764,430		729,596
Transportation and other	8,336		12,541		15,039
Total natural gas revenues	$	889,958	$	776,971	$	744,635
MMBtu sales per retail customer	178.38		171.38		151.43
Revenue per retail customer	$	1,855	$	1,628	$	1,567
Residential revenue per MMBtu	11.25		10.88		11.63
Commercial and industrial revenue per MMBtu	9.71		8.73		9.52
Transportation and other revenue per MMBtu	0.67		1.47		1.72

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ENVIRONMENTAL MATTERS

NSP-Minnesota’s facilities are regulated by federal and state environmental agencies.  These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances.  Various company activities require registrations, permits, licenses, inspections and approvals from these agencies.  NSP-Minnesota has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems.  NSP-Minnesota facilities have been designed and constructed to operate in compliance with applicable environmental standards.

NSP-Minnesota strives to comply with all environmental regulations applicable to its operations.  However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon NSP-Minnesota’s operations.  For more information on environmental contingencies, see Notes 14 and 15 to the consolidated financial statements.

EMPLOYEES

The number of full-time NSP-Minnesota employees on Dec. 31, 2008 was 3,637.  Of these full-time employees, 2,279 or 63 percent, are covered under collective bargaining agreements.  See Note 8 in the consolidated financial statements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to NSP-Minnesota and are not considered in the above amounts.

Item 1A — Risk Factors

Risks Associated with Our Business

Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies.  The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers.  The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers.  We currently provide service at rates approved by one or more regulatory commissions.  These rates are generally regulated based on an analysis of our expenses incurred in a test year.  Thus, the rates we are allowed to charge may or may not match our expenses at any given time.  While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs.  Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers.  Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.  If all of our costs are not recovered through customer rates, we could incur financial operating losses, which, over the long term, could jeopardize our ability to meet our financial obligations.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place.  However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.  In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies.  For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts.  An increase in the overall

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level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology.  Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined.  Any downgrade could lead to higher borrowing costs.

We are subject to interest rate risk.

If interest rates increase, we may incur increased interest expense on variable interest debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.

We are subject to capital market risk.

NSP-Minnesota’s operations require significant capital investment in property, plant and equipment; consequently, NSP-Minnesota is an active participant in debt markets.  Any disruption in capital markets could have a material impact on our ability to fund our operations.  Capital markets are global in nature and are impacted by numerous events throughout the world economy.  Capital market disruption events, as evidenced by the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, could prevent NSP-Minnesota from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.

Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations.  Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements.  In that event, our financial results could be adversely affected and we could incur losses.

NSP-Minnesota may at times have direct credit exposure in its short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties.  NSP-Minnesota may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.

NSP-Minnesota does have additional indirect credit exposures to various financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts.  If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long term purchased power contracts, the supplier would need to replace that security with an acceptable substitute.  If the security were not replaced, the party would be in technical default under the contract, which would enable NSP-Minnesota to exercise its contractual rights.

We are subject to commodity risks and other risks associated with energy markets.

We engage in wholesale sales and purchases of electric capacity, energy and energy-related products and are subject to market supply and commodity price risk.  Commodity price changes can affect the value of our commodity trading derivatives.  We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility.  We utilize quoted observable market prices to the maximum extent possible in determining the value of these derivative commodity instruments.  For positions for which observable market prices are not available, we utilize observable quoted market prices of similar assets or liabilities or indirectly observable prices based on forward price curves of similar markets.  For positions for which we have unobservable market prices, we incorporate estimates and assumptions as to a variety of factors such as pricing relationships between various energy commodities and geographic locations.  Actual experience can vary significantly from these estimates and assumptions and significant changes from our assumptions could cause significant earnings variability.

If we encounter market supply shortages, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such supply shortages could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations.  Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses.  Potential market supply shortages may not be fully resolved through alternative

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supply sources and such interruptions may cause short-term disruptions in our ability to provide electric and/or natural gas services to our customers.

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances.  These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals.  Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination.  Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us.  We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination.  At Dec. 31, 2008, these sites included:

·Sites of former MGPs operated by us, our predecessors, or other entities; and

·Third party sites, such as landfills, at which we are alleged to be a potentially responsible party that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings.  These mandates are designed in part to mitigate the potential environmental impacts of utility operations.  Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

In addition, existing environmental laws or regulations may be revised, new laws or regulations seeking to protect the environment may be adopted or become applicable to us and we may incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change.  Climate change creates physical and financial risk.  Physical risks from climate change include an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events.  NSP-Minnesota does not serve any coastal communities so the possibility of sea level rises does not directly affect NSP-Minnesota or its customers.  Our customers’ energy needs vary with weather conditions, primarily temperature and humidity.  For residential customers, heating and cooling represent their largest energy use.  To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.  Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load.  Decreased energy use due to weather changes may affect our financial condition, through decreased revenues.  Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions.  Weather conditions outside of the company’s service territory could also have an impact on NSP-Minnesota’s revenues.  NSP-Minnesota buys and sells electricity depending upon system needs and market opportunities.  Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.  Severe weather impacts NSP-Minnesota’s service territories, primarily through thunderstorms, tornadoes and snow or ice storms.  We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so.  To the extent the frequency of extreme weather events increases, this could increase our cost of providing service.  Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units.  A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy.  We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact NSP-Minnesota’s revenues.  NSP-Minnesota’s financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities.  The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation,

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would normally be borne by consumers through higher prices for energy and purchased goods.  To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause NSP-Minnesota to receive less than ideal terms and conditions.

We may be subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Legislative and regulatory responses related to climate change create financial risk.  Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG.  Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress.  Likewise, the EPA has issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act.  NSP-Minnesota’s electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.  NSP-Minnesota is advocating with state and federal policy makers to design climate change regulation that is effective, flexible, low-cost and consistent with our environmental leadership strategy.

Many of the federal and state climate change legislative proposals use a “cap and trade” policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap.  Under the proposals, the cap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year.  The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emissions for their own operations.  Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions.  The impact of legislation and regulations, including a “cap and trade” structure, on NSP-Minnesota and its customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices.  An important factor is NSP-Minnesota’s ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not recover all costs related to complying with regulatory requirements imposed on NSP-Minnesota.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion see Note 14 to the consolidated financial statements.

We are subject to the risks of nuclear generation.

Our two nuclear stations, Prairie Island and Monticello, subject us to the risks of nuclear generation, which include:

·The risks associated with storage, handling and disposal of radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

·Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

·Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities.  In the event of non-compliance, the NRC has the authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved.  Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at NSP-Minnesota’s nuclear plants.  In addition, the Institute for Nuclear Power Operations (INPO) reviews our nuclear operations and nuclear generation facilities. Compliance with INPO recommendations could result in substantial capital expenditures or a substantial increase in operating expenses.

If an incident did occur, it could have a material adverse effect on our results of operations or financial condition.  Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could then increase NSP-Minnesota’s compliance costs and impact the results of operations of its facilities.

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Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets.  A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth.  Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the Capital Markets risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.  It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur.  See credit risk section for more related information.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies.  Additionally, the cost of those commodities may be higher than expected.

Our utility operations are subject to long term planning risks.

On a periodic basis, or as needed, our utility operations file long term resource plans with our regulators.  These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model.  Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide.  This could lead to under recovery of costs or insufficient resources to meet customer demand.

Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations.  The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business.  While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, including our nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security and additional security personnel.

The insurance industry has also been affected by these events and the availability of insurance covering risks our competitors and we typically insure against may decrease.  In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business.  Because our generation, transmission systems and local natural gas distribution companies are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, sudden and significant increase or decrease in wind generation, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system or the actions of a neighboring utility.  Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.

We are subject to business continuity risks associated with our ability to respond to unforeseen events.

The term business continuity refers to the ability of the firm to maintain day-to-day operations in response to unforeseen events, such as those in the preceding section, which describes numerous disruptions to our normal operating environment.  While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations.  The

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company’s response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm’s on-going business operations.

Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results.  It’s difficult to predict the magnitude of such events and associated impacts.

We are subject to information security risks.

A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information.  We are unable to quantify the potential impact of such an event.

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful.  In addition, the higher fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on our results of operations.  Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows.  We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric and natural gas utility businesses are seasonal businesses, and weather patterns can have a material impact on our operating performance.  Demand for electricity is often greater in the summer and winter months associated with cooling and heating.  Because natural gas is heavily used for residential and commercial heating, the demand for this product depends heavily upon weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season.  Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer.  Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.

Our natural gas distribution activities involve numerous risks that may result in accidents and other operating risks and costs.

There are inherent in our natural gas distribution activities a variety of hazards and operating risks, such as leaks, explosions and mechanical problems, which could cause substantial financial losses.  In addition, these risks could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us.  In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses.

The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.  For our distribution lines located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damages resulting from these risks is greater.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased the FERC’s civil penalty authority for violation of FERC statutes, rules and orders.  The FERC can now impose penalties of $1 million per violation per day.  In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations.  If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

Increasing costs associated with our defined benefit retirement plans and other employee-related benefits may adversely affect our results of operations, financial position or liquidity.

We have defined benefit and postretirement plans that cover substantially all of our employees.  Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans.  These estimates and assumptions may change based on economic conditions, actual

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stock market performance, changes in interest rates and any changes in governmental regulations.  In addition, the Pension Protection Act of 2006, as amended, changed the minimum funding requirements for defined benefit pension plans beginning in 2008.  Therefore, our funding requirements and related contributions may change in the future.

Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

As we are a subsidiary of Xcel Energy, we may be negatively affected by events at Xcel Energy and its affiliates.  If Xcel Energy were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if Xcel Energy’s credit ratings and access to capital were restricted, this could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures.  If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets.  This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2008, Xcel Energy had approximately $7.7 billion of long-term debt and $1.0 billion of short-term debt and current maturities.  Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries of specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters.  Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions.  The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees.  As of Dec. 31, 2008, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $67.5 million and $18.2 million of exposure.  Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with these indemnities outstanding as of Dec. 31, 2008, was approximately $27.9 million.  Xcel Energy’s total exposure under these indemnities cannot be determined at this time.  If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund the other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends.  If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

We are a wholly owned subsidiary of Xcel Energy.  Xcel Energy can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

Our board of directors, as well as many of our executive officers, are officers of Xcel Energy.  Our board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy.  In 2008, 2007 and 2006 we paid $229.7 million, $226.8 million and $219.6 million of dividends to Xcel Energy, respectively.  If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs.  This could adversely affect our liquidity.  The amount of dividends that we can pay is also limited to some extent by our indenture for our first mortgage bonds.

Item 1B — Unresolved SEC Staff Comments

None.

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Item 2 — Properties

Virtually all of the utility plant of NSP-Minnesota is subject to the lien of its first mortgage bond indenture.

Electric utility generating stations:

Station, City and Unit	Fuel	Installed	Summer 2008 Net Dependable Capability (MW)
Steam:
Sherburne-Becker, MN
Unit 1	Coal	1976	697
Unit 2	Coal	1977	697
Unit 3	Coal	1987	510	(a)
Prairie Island-Welch, MN
Unit 1	Nuclear	1973	551
Unit 2	Nuclear	1974	545
Monticello-Monticello, MN	Nuclear	1971	572
King-Bayport, MN	Coal	1968	555
Black Dog-Burnsville, MN
2 Units	Coal/Natural Gas	1955-1960	282
2 Units	Natural Gas	1987-2002	298
Riverside-Minneapolis, MN
2 Units	Coal	1964-1987	371
Combustion Turbine:
Angus Anson-Sioux Falls, SD
3 Units	Natural Gas	1994-2005	384
High Bridge-St. Paul, MN
3 Units	Natural Gas	2008	566
Inver Hills-Inver Grove Heights, MN
6 Units	Natural Gas	1972	350
Blue Lake-Shakopee, MN
6 Units	Natural Gas	1974-2005	490
Various locations
28 Units	Various	Various	165
Wind:
Grand Meadow-Mower County, MN		2008	101	(b)
		Total	7,134

(a)Based on NSP-Minnesota’s ownership interest of 59 percent.

(b)Installed December 2008; Amount represents nameplate rating capacity.

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2008:

Conductor Miles

500 KV	2,917
345 KV	5,852
230 KV	1,801
161 KV	405
115 KV	6,743
Less than 115 KV	82,448

NSP-Minnesota had 372 electric utility transmission and distribution substations at Dec. 31, 2008.

Natural gas utility mains at Dec. 31, 2008:

	Miles
Transmission	135
Distribution	9,506

Item 3 — Legal Proceedings

In the normal course of business, various lawsuits and claims have arisen against NSP-Minnesota.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

For a discussion of legal claims and environmental proceedings, see Note 14 to the consolidated financial statements.  For a discussion of proceedings involving utility rates, see Public Utility Regulation and Summary of Recent Federal Regulatory Developments under Item 1 and Note 13 to the consolidated financial statements.

Item 4 — Submission of Matters to a Vote of Security Holders

This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

NSP-Minnesota is a wholly owned subsidiary and there is no market for its common equity securities.

NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $999 million in additional cash dividends on common stock at Dec. 31, 2008.  In addition, NSP-Minnesota had dividend restrictions imposed by its credit agreement, FERC rules and state regulatory commissions.

·Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

·Covenant restrictions under NSP-Minnesota’s credit agreement include a required debt to total capital ratio.

·State regulatory commissions indirectly limit the amount of dividends NSP-Minnesota can pay to Xcel Energy by requiring a minimum equity ratio of 46.26%.

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The dividends declared during 2008 and 2007 were as follows:

Quarter Ended (Thousands of Dollars)
March 31, 2008		June 30, 2008		Sept. 30, 2008		Dec. 31, 2008
$	56,668	$	58,449	$	58,501	$	58,414

Quarter Ended (Thousands of Dollars)
March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007
$	57,124	$	57,312	$	56,282	$	56,094

Item 6 — Selected Financial Data

This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations

Discussion of financial condition and liquidity for NSP-Minnesota is omitted per conditions set forth in general instructions I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries.  It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of NSP-Minnesota during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the respective accompanying consolidated financial statements and notes to the consolidated financial statements.

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of NSP- Minnesota to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by NSP-Minnesota; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates, have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions of accounting regulatory bodies; the items described under “Risk Factors” in Item 1A and Exhibit 99.01 of NSP-Minnesota’s Form 10-K for the year ended Dec. 31, 2008.

Results of Operations

NSP-Minnesota’s net income was approximately $285.1 million for 2008, compared with approximately $267.3 million for 2007.

Electric Revenues and Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power.  Due to fuel and purchased energy cost-recovery mechanisms for customers,  fluctuations in these costs do not materially affect electric utility margin.

28

NSP-Minnesota has two distinct forms of wholesale sales: short-term wholesale and commodity trading activities.  Short-term wholesale refers to energy-related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from, NSP-Minnesota’s generation assets and energy and capacity purchased to serve native load.  Commodity trading is not associated with NSP-Minnesota’s generation assets or the energy or capacity purchased to serve native load.  Wholesale sales were immaterial to revenue and gross margin as a percentage of revenue at Dec. 31, 2008 and 2007.

Electric — The following tables detail the electric revenues and margin:

(Millions of Dollars)	2008			2007
Electric revenues	$	3,584		$	3,477
Electric fuel and purchased power	(1,681		)	(1,577		)
Electric margin	$	1,903		$	1,900

The following summarizes the components of the changes in electric revenues and electric margin for the year ended Dec. 31:

Electric Revenues

(Millions of Dollars)	2008 vs. 2007
Fuel and purchased power cost recovery	$	94
MERP rider	23
Interchange agreement billing with NSP-Wisconsin	18
Conservation and non-fuel riders	17
Transmission revenues	15
North Dakota interim rate increase	9
Increased revenues due to leap year (weather-normalized impact)	4
Estimated impact of weather	(31		)
Trading revenue	(25		)
Revenue subject to refund due to change in nuclear refueling outage recovery method	(14		)
Other	(3		)
Total increase in electric revenues	$	107

Electric Margin

(Millions of Dollars)	2008 vs. 2007
Estimated impact of weather	$	(31	)
Purchased capacity costs	(20		)
Revenue subject to refund due to change in nuclear refueling outage recovery method	(14		)
MERP rider	23
Conservation and non-fuel riders	17
Interchange agreement billing with NSP-Wisconsin	13
North Dakota interim rate increase	9
Increased margin due to leap year (weather-normalized impact)	4
Transmission revenues, net	3
Firm wholesale	3
Other	(4		)
Total increase in electric margin	$	3

29

Natural Gas Revenues and Margins

The following table details natural gas revenues and margin.  The cost of natural gas tends to vary with changing sales requirements and unit cost of natural gas purchases.  However, due to purchased natural gas cost recovery mechanisms for retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin.

(Millions of Dollars)	2008			2007
Natural gas revenues	$	890		$	777
Cost of natural gas sold and transported	(702		)	(603		)
Natural gas margin	$	188		$	174

The following summarizes the components of the changes in natural gas revenues and margin for the year ended Dec. 31:

Natural Gas Revenues

(Millions of Dollars)	2008 vs. 2007
Purchased natural gas adjustment clause recovery	$	97
Estimated impact of weather	8
2007 Kansas property tax refund	4
Conservation revenues	3
Other	1
Total increase in natural gas revenues	$	113

Natural Gas Margin

(Millions of Dollars)	2008 vs. 2007
Estimated impact of weather	$	8
2007 Kansas property tax refund	4
Conservation revenues	3
Other	(1		)
Total increase in natural gas margin	$	14

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Operating and maintenance expenses for 2008 decreased $7.1 million, or 0.8 percent, compared to 2007.  The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2008 vs. 2007
Nuclear outage expenses, net of deferral	$	(13	)
Lower employee benefit costs	(12		)
Higher labor costs	9
Higher contract labor costs	5
Higher consulting costs	3
Higher allowance for bad debts	3
Other	(2		)
Total decrease in other operating and maintenance expenses	$	(7	)

Depreciation and Amortization — Depreciation and amortization expense increased by approximately $6.8 million, or 1.7 percent, for 2008, compared to 2007.  The increase was primarily due to planned system expansion, which was partially offset by a decrease in depreciation due to the MPUC approval of two NSP-Minnesota depreciation filings in September 2008, and an NDPSC settlement agreement in December 2008.

Allowance for Funds Used During Construction, Equity and Debt (AFDC) — AFDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally, these costs are recovered from customers, in future rates, as the related property is depreciated.  AFDC, resulting in part from these projects, increased by approximately $4.5 million, or 11.5 percent, for the twelve months of 2008 compared with the same period in 2007.  NSP-Minnesota’s overall increase in AFDC is due to the RES Project (which is partially offset by the current recovery from customers of the financing costs through a rate rider) and various nuclear projects.

30

Interest Charges — Interest charges increased by approximately $12.1 million, or 6.5 percent, for 2008, compared with 2007.  The increase was due to higher average debt balances.

Income Taxes — Income tax expense decreased by approximately $3.8 million for 2008 compared with 2007.  The decrease in tax expense in 2008 was primarily due to higher state tax expense in 2007 and higher plant-related deductions in 2008.  The effective tax rate was 38.5 percent for 2008, compared with 40.5 percent for 2007.  Without the increases in these charges and benefits, the effective tax rate for 2008 and 2007 would have been 39.2 percent and 39.9 percent, respectively.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  All financial and commodity-related instruments, including derivatives, are subject to market risk.  These risks, as applicable to NSP-Minnesota, are discussed in further detail in Note 10 to the consolidated financial statements.

NSP-Minnesota is exposed to the impact of changes in price for energy and energy-related products, which is partially mitigated by the company’s use of commodity derivatives.  Though no material non-performance risk currently exists with the counterparties to NSP-Minnesota’s commodity derivative contracts, the continued turmoil in the financial markets may in the future impact that risk to the extent it impacts those counterparties.  Continued distress in the financial markets may also impact the fair value of the debt and equity securities in the nuclear decommissioning trust fund and master pension trust, as well as NSP-Minnesota’s ability to earn a return on short-term investments of excess cash.  Also, the current state of the financial markets may negatively impact NSP-Minnesota’s ability to obtain debt financing under favorable terms.

Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its electric and natural gas operations.  Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in the generation and distribution activities.  Commodity price risk is also managed through the use of financial derivative instruments.  NSP-Minnesota’s risk-management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists, as allowed by regulation.

Short-Term Wholesale and Commodity Trading Risk — NSP Minnesota conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  These marketing activities generally have terms of less than one year in length.  NSP Minnesota’s risk-management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

The fair value of the commodity trading contracts at Dec. 31, were as follows:

(Thousands of Dollars)	2008			2007
Fair value of commodity trading contract assets (liabilities) outstanding at Jan. 1	$	2,112		$	(1,174	)
Contracts realized or settled during the period	(2,391		)	(12,073		)
Fair value of commodity trading contract additions and changes during the period	3,894			15,359
Fair value of commodity trading contract assets outstanding at Dec. 31	$	3,615		$	2,112

31

At Dec. 31, 2008, the fair values by source for the commodity trading net asset (liability) balances were as follows:

	Futures/Forwards
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year		Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Futures/  Forwards Fair Value
	1	$	1,936	$	1,133	$	—	$	—	$	3,069
	2	91		291		359		158		899
Total Futures/Forwards Fair Value		$	2,027	$	1,424	$	359	$	158	$	3,968

	Options
(Thousands of Dollars)	Source of Fair Value	Maturity Less Than 1 Year			Maturity 1 to 3 Years		Maturity 4 to 5 Years		Maturity Greater Than 5 Years		Total Options Fair Value
	2	$	(353	)	$	—	$	—	$	—	$	(353	)
Total Options Fair Value		$	(353	)	$	—	$	—	$	—	$	(353	)

(1)	—	Prices actively quoted or based on actively quoted prices.
(2)	—	Prices based on models and other valuation methods.  These represent the fair value of positions calculated using internal models when directly and indirectly quoted external prices or prices derived from external sources are not available.  Internal models incorporate the use of options pricing and estimates of the present value of cash flows based upon underlying contractual terms.  The models reflect management’s estimates, taking into account observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated correlations of commodity prices and contractual volumes.  Market price uncertainty and other risks also are factored into the model.

Normal purchases and sales transactions, as defined by SFAS No. 133, hedge transactions and certain other long-term power purchase contracts are not included in the fair values by source tables as they are not recorded at fair value as part of commodity trading operations.

NSP-Minnesota’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions, contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR).  VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time under normal market conditions.

VaR is calculated on a consolidated basis.  The VaRs for the commodity trading operations were:

	Year ended				During 2008
(Millions of Dollars)	Dec. 31, 2008		VaR Limit		Average		High		Low
Commodity trading (a)	$	0.30	$	5.00	$	0.30	$	1.14	$	0.01

	Year ended				During 2007
(Millions of Dollars)	Dec. 31, 2007		VaR Limit		Average		High		Low
Commodity trading (a)	$	0.26	$	5.00	$	0.47	$	1.45	$	0.09

(a) Includes transactions for NSP-Minnesota and PSCo.

Interest Rate Risk — NSP-Minnesota is subject to the risk of fluctuating interest rates in the normal course of business.  NSP-Minnesota’s risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options, subject to regulatory approval when required.

At Dec. 31, 2008, a 100-basis-point change in the benchmark rate on NSP-Minnesota’s variable rate debt would impact pretax interest expense by approximately $1.3 million.

NSP-Minnesota also maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning.  These trust funds are subject to interest rate risk and equity price risk.  At Dec. 31, 2008, these funds were invested in a diversified portfolio of taxable and municipal fixed income securities and equity securities.  These funds may be used only for activities

32

related to nuclear decommissioning.  The accounting for nuclear decommissioning recognizes that costs are recovered through rates; therefore fluctuations in equity prices, or interest rates do not have an impact on earnings.

Credit Risk — NSP-Minnesota is also exposed to credit risk.  Credit risk relates to the risk of loss resulting from the nonperformance by a counterparty of its contractual obligations.  NSP-Minnesota maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations.

NSP-Minnesota conducts standard credit reviews for all counterparties.  NSP-Minnesota employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  The credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.  The recent volatility in financial markets could increase our credit risk.

At Dec. 31, 2008, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $1.0 million, while a decrease of 10 percent would have resulted in a decrease of $0.9 million.

33

Item 8 — Financial Statements and Supplementary Data

Management Report on Internal Controls Over Financial Reporting

The management of NSP-Minnesota is responsible for establishing and maintaining adequate internal control over financial reporting.  NSP-Minnesota’s internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations.  Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

NSP-Minnesota management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2008.  In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework.  Based on our assessment, we believe that, as of Dec. 31, 2008, the company’s internal control over financial reporting is effective based on those criteria.

This annual report does not include an attestation report of NSP-Minnesota’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by NSP-Minnesota’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit NSP-Minnesota to provide only management’s report in this annual report.

/S/ DAVID M. SPARBY	/S/ BENJAMIN G.S. FOWKE III
David M. Sparby	Benjamin G.S. Fowke III
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer
March 2, 2009	March 2, 2009

34

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders
Northern States Power Company — Minnesota

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northern States Power Company — Minnesota and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of income, common stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008.  Our audits also included the financial statement schedule listed in the Index at Item 15.  These financial statements and financial statement schedule are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern States Power Company — Minnesota and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.  Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.  As discussed in Note 7 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109,” as of January 1, 2007.

/S/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 2, 2009

35

NSP-MINNESOTA AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF INCOME
(amounts in thousands of dollars)

	Year Ended Dec. 31
	2008			2007			2006
Operating revenues
Electric	$	3,584,109		$	3,476,674		$	3,265,371
Natural gas	889,958			776,971			744,635
Other	19,569			18,569			17,609
Total operating revenues	4,493,636			4,272,214			4,027,615
Operating expenses
Electric fuel and purchased power	1,680,795			1,576,901			1,445,590
Cost of natural gas sold and transported	701,687			602,617			590,094
Cost of sales — nonregulated and other	10,034			9,212			7,769
Other operating and maintenance expenses	877,497			884,554			842,801
Conservation program expenses	65,876			72,912			59,436
Depreciation and amortization	412,362			405,569			425,511
Taxes (other than income taxes)	138,184			130,094			135,903
Total operating expenses	3,886,435			3,681,859			3,507,104
Operating income	607,201			590,355			520,511
Interest and other income — net	10,895			6,105			9,431
Allowance for funds used during construction — equity	26,510			21,826			20,896
Interest charges and financing costs
Interest charges — including financing costs of $5,834, $5,271 and $6,480, respectively	198,369			186,293			165,381
Allowance for funds used during construction — debt	(17,140		)	(17,334		)	(14,459		)
Total interest charges and financing costs	181,229			168,959			150,922
Income before income taxes	463,377			449,327			399,916
Income taxes	178,236			182,025			127,606
Net income	$	285,141		$	267,302		$	272,310

See Notes to Consolidated Financial Statements

36

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(amounts in thousands of dollars)

	Year Ended Dec. 31
	2008			2007			2006
Operating activities
Net income	$	285,141		$	267,302		$	272,310
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	407,343			415,651			433,883
Nuclear fuel amortization	64,203			53,453			47,531
Deferred income taxes	140,701			172,004			(83,361		)
Amortization of investment tax credits	(3,503		)	(3,897		)	(4,846		)
Allowance for equity funds used during construction	(26,510		)	(21,826		)	(20,896		)
Allowance for bad debts	25,506			23,336			19,972
Net realized and unrealized hedging and derivative transactions	(4,484		)	(5		)	17,587
Changes in operating assets and liabilities (net of the effects of consolidation of NMC, see Note 18)
Accounts receivable	3,268			(86,108		)	8,071
Accounts receivable from affiliates	18,660			1,858			20,479
Accrued unbilled revenues	(22,050		)	(6,367		)	37,994
Inventories	(75,265		)	(52,226		)	(6,475		)
Recoverable purchased natural gas and electric energy costs	10,252			(19,184		)	(1,347		)
Other current assets	11,394			(2,790		)	(1,905		)
Accounts payable	14,557			(66,920		)	49,691
Net regulatory assets and liabilities	(23,128		)	(14,661		)	(79,181		)
Other current liabilities	(13,348		)	7,624			(1,264		)
Change in other noncurrent assets	15,781			17,719			28,675
Change in other noncurrent liabilities	(37,139		)	(38,139		)	16,626
Net cash provided by operating activities	791,379			646,824			753,544
Investing activities
Utility capital/construction expenditures	(1,015,827		)	(1,060,796		)	(905,352		)
Allowance for equity funds used during construction	26,510			21,826			20,896
Purchase of investments in external decommissioning fund	(957,752		)	(712,462		)	(1,288,104		)
Proceeds from sale of investments in external decommissioning fund	914,514			669,070			1,240,034
Cash obtained from consolidation of NMC	—			38,950			—
Investments in utility money pool arrangement	(943,400		)	(423,500		)	(1,359,000		)
Receipts from utility money pool arrangement	943,400			423,500			1,359,000
Investments in affiliates	(337,600		)	(371,250		)	(345,500		)
Advances from affiliates	396,200			342,950			379,200
Other investments	10,501			5,224			6,439
Net cash used in investing activities	(963,454		)	(1,066,488		)	(892,387		)
Financing activities
Proceeds from (repayment of) short-term borrowings — net	(276,500		)	252,500			89,000
Borrowings under utility money pool arrangement	433,300			937,600			—
Repayments under utility money pool arrangement	(464,900		)	(842,500		)	—
Proceeds from issuance of long-term debt	493,751			343,670			393,724
Borrowings under 5-year unsecured credit facility	—			200,000			194,000
Repayment of long-term debt, including reacquisition premiums	(10		)	(186,689		)	(210,662		)
Repayments under 5-year unsecured credit facility	—			(200,000		)	(444,000		)
Capital contributions from parent	203,863			150,514			313,856
Dividends paid to parent	(229,712		)	(226,824		)	(219,598		)
Net cash provided by financing activities	159,792			428,271			116,320
Net (decrease) increase in cash and cash equivalents	(12,283		)	8,607			(22,523		)
Cash and cash equivalents at beginning of year	24,626			16,019			38,542
Cash and cash equivalents at end of year	$	12,343		$	24,626		$	16,019
Supplemental disclosure of cash flow information
Cash paid for interest (net of amounts capitalized)	$	170,168		$	151,409		$	145,585
Cash paid for income taxes (net of refunds received)	27,292			50,016			227,285
Supplemental disclosure of non-cash flow information
Property, plant and equipment additions in accounts payable	$	24,109		$	15,670		$	36,613

See Notes to Consolidated Financial Statements

37

NSP-MINNESOTA AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31, 2008		Dec. 31, 2007
Assets
Current assets:
Cash and cash equivalents	$	12,343	$	24,626
Notes receivable from affiliates	—		58,600
Accounts receivable, net	413,156		441,930
Accounts receivable from affiliates	12,418		31,078
Accrued unbilled revenues	248,451		226,401
Recoverable purchased natural gas and electric energy costs	26,605		36,857
Inventories	345,903		270,638
Derivative instruments valuation	70,252		51,233
Prepayments and other	48,493		52,875
Total current assets	1,177,621		1,194,238
Property, plant and equipment, net	6,804,794		6,482,681
Other assets:
Nuclear decommissioning fund and other investments	1,084,827		1,337,598
Regulatory assets	828,712		359,782
Prepaid pension asset	—		270,436
Derivative instruments valuation	129,605		156,975
Other	21,266		18,622
Total other assets	2,064,410		2,143,413
Total assets	$	10,046,825	$	9,820,332
Liabilities and Equity
Current liabilities:
Current portion of long-term debt	$	250,060	$	31
Short-term debt	65,000		341,500
Borrowings under utility money pool arrangement	63,500		95,100
Accounts payable	389,676		369,394
Accounts payable to affiliates	52,291		53,975
Taxes accrued	121,163		122,648
Accrued interest	68,009		61,485
Dividends payable to parent	58,414		56,094
Derivative instruments valuation	39,816		23,311
Other	50,696		64,968
Total current liabilities	1,158,625		1,188,506
Deferred credits and other liabilities:
Deferred income taxes	987,050		898,725
Deferred investment tax credits	40,254		43,757
Asset retirement obligations	1,055,689		1,264,368
Regulatory liabilities	459,880		639,228
Derivative instruments valuation	219,421		236,832
Pension and employee benefit obligations	269,537		201,624
Other liabilities	77,775		68,585
Total deferred credits and other liabilities	3,109,606		3,353,119
Commitments and contingent liabilities
Capitalization:
Long-term debt	2,712,689		2,463,078
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares	10		10
Additional paid in capital	1,915,857		1,711,994
Retained earnings	1,149,833		1,097,357
Accumulated other comprehensive income	205		6,268
Total common stockholder’s equity	3,065,905		2,815,629
Total liabilities and equity	$	10,046,825	$	9,820,332

See Notes to Consolidated Financial Statements

38

NSP-MINNESOTA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME
(amounts in thousands of dollars)

									Accumulated			Total
									Other			Common
	Common Stock			Additional Paid		Retained			Comprehensive			Stockholder’s
	Shares	Amount		in Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2005	1,000,000	$	10	$	1,247,624	$	1,004,762		$	—		$	2,252,396
Net income						272,310						272,310
Net derivative instrument fair value changes during the period, net of tax of $6,513									9,433			9,433
Comprehensive income for 2006												281,743
SFAS No. 158 adoption, net of tax of $(2,233)									(3,234		)	(3,234		)
Common dividends declared to parent						(221,089		)				(221,089		)
Contribution of capital by parent				313,856								313,856
Balance at Dec. 31, 2006	1,000,000	$	10	$	1,561,480	$	1,055,983		$	6,199		$	2,623,672
FIN 48 adoption						884						884
Net income						267,302						267,302
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $551									797			797
Net derivative instrument fair value changes during the period, net of tax of $(503)									(728		)	(728		)
Comprehensive income for 2007												268,255
Common dividends declared to parent						(226,812		)				(226,812		)
Contribution of capital by parent				150,514								150,514
Balance at Dec. 31, 2007	1,000,000	$	10	$	1,711,994	$	1,097,357		$	6,268		$	2,815,629
EITF 06-4 adoption, net of tax of $(401)						(633		)				(633		)
Net income						285,141						285,141
Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $(285)									(412		)	(412		)
Net derivative instrument fair value changes during the period, net of tax of $(3,901)									(5,651		)	(5,651		)
Comprehensive income for 2008												279,078
Common dividends declared to parent						(232,032		)				(232,032		)
Contribution of capital by parent				203,863								203,863
Balance at Dec. 31, 2008	1,000,000	$	10	$	1,915,857	$	1,149,833		$	205		$	3,065,905

See Notes to Consolidated Financial Statements

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NSP-MINNESOTA AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands of dollars)

	Dec. 31
	2008			2007
Long-Term Debt
First Mortgage Bonds, Series due:
Aug. 1, 2010, 4.75%	$	175,000		$	175,000
Aug. 28, 2012, 8%	450,000			450,000
March 1, 2018, 5.25%	500,000			—
March 1, 2019, 8.5% (a)	27,900			27,900
Sept. 1, 2019, 8.5% (a)	100,000			100,000
July 1, 2025, 7.125%	250,000			250,000
March 1, 2028, 6.5%	150,000			150,000
April 1, 2030, 8.5% (a)	69,000			69,000
July 15, 2035, 5.25%	250,000			250,000
June 1, 2036, 6.25%	400,000			400,000
July 1, 2037, 6.2%	350,000			350,000
Senior Notes due Aug. 1, 2009, 6.875%	250,000			250,000
Other	107			31
Unamortized discount	(9,258		)	(8,822		)
Total	2,962,749			2,463,109
Less current maturities	250,060			31
Total long-term debt	$	2,712,689		$	2,463,078
Common Stockholder’s Equity
Common stock — authorized 5,000,000 shares of $0.01 par value; outstanding 1,000,000 shares in 2008 and 2007	$	10		$	10
Additional paid in capital	1,915,857			1,711,994
Retained earnings	1,149,833			1,097,357
Accumulated other comprehensive income	205			6,268
Total common stockholder’s equity	$	3,065,905		$	2,815,629

(a)   Pollution control financing

See Notes to Consolidated Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Minnesota is principally engaged in the generation, purchase, transmission, distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas.  NSP-Minnesota is subject to regulation by the FERC and state utility commissions.  All of NSP-Minnesota’s accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation — NSP-Minnesota has subsidiaries, which have been consolidated and for which all intercompany transactions and balances have been eliminated.

During 2007, NSP-Minnesota became the sole remaining partner in NMC.  This is the result of the remaining partner leaving NMC during 2007.  The exiting company was required to pay an exit fee and surrender its equity interest in NMC.  NSP-Minnesota owns 100 percent of the equity and has a controlling interest in NMC.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers.  However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated.  NSP-Minnesota presents its revenue net of any excise or other fiduciary-type taxes or fees.

NSP-Minnesota has various rate-adjustment mechanisms in place that currently provide for the recovery of purchased natural gas and electric fuel and purchased energy costs.  These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates, and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred.  Where applicable under governing state regulatory commission rate orders, fuel costs over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as current regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as current regulatory assets.  A summary of significant rate adjustment mechanisms follows:

·NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing recovery of the respective costs, which are trued-up on a two-month and annual basis, respectively.  The electric cost-of-fuel-and-purchased-energy mechanism in Minnesota and North Dakota also provides a sharing among shareholders and customers of certain margins on short-term wholesale and commodity trading.

·NSP-Minnesota operates under various service quality standards, which could require customer refunds if certain criteria are not met.  NSP-Minnesota’s rates in Minnesota include monthly adjustments for the recovery of conservation and energy-management program costs, which are reviewed annually.  NSP-Minnesota is allowed to recover certain costs associated with new transmission facilities to deliver renewable energy resources and certain costs associated with production facilities through rate riders.

·NSP-Minnesota sells firm power and energy in wholesale markets, which are regulated by the FERC.  Certain of these rates include monthly wholesale fuel cost-recovery mechanisms.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the consolidated statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from NSP-Minnesota are apportioned to PSCo and SPS.  Commodity trading activities are not associated with energy produced from NSP-Minnesota’s generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value in accordance with SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133).  In addition, commodity trading results include the impact of all margin-sharing mechanisms.  For more information, see Note 10 to the consolidated financial statements.

Fair Value Measurements —NSP-Minnesota presents cash equivalents, commodity derivatives and nuclear decommissioning fund assets at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest to approximate fair value.  Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost.  For commodity derivatives, the most

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observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Minnesota may use quoted prices for similar contracts, or internally prepared valuation models as primary inputs to determine fair value.  For the nuclear decommissioning fund, published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each class of security.

Types of and Accounting for Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation.  This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification is dependent on the applicability of specific regulation.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue; hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas purchased for resale are recorded as a component of natural gas costs; vehicle fuel costs are recorded as a component of capital project or O&M costs; and interest rate hedging transactions are recorded as a component of interest expense.  NSP-Minnesota is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.

Cash Flow Hedges — Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  The designation of a cash flow hedge permits changes in fair value to be recorded within other comprehensive income (OCI), to the extent the hedge is effective, or deferred as a regulatory asset or liability.

SFAS No. 133 requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting.  NSP-Minnesota formally documents all hedging relationships in accordance with SFAS No. 133.  The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction.  In addition, at inception and on a quarterly basis, NSP-Minnesota formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability until earnings are affected by the hedged transaction.  NSP-Minnesota discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur.  To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis.  Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case, associated deferred amounts are immediately recognized in current earnings.

Normal Purchases and Normal Sales — NSP-Minnesota enters into contracts for the purchase and sale of commodities for use in their business operations.  SFAS No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales.

NSP-Minnesota evaluates all of its contracts at inception to determine if they are derivatives and, if so, if they qualify to meet the normal purchases and normal sales designation requirements under SFAS No. 133.  None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

For further discussion of NSP-Minnesota’s risk management and derivative activities, see Note 10 to the consolidated financial statements.

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Property, Plant, and Equipment and Depreciation — Property, plant and equipment is stated at original cost.  The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense.  The cost of plant retired is charged to accumulated depreciation and amortization.  Regulatory obligations to incur removal costs are recorded as regulatory liabilities.  Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred.  Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred.  Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use.

NSP-Minnesota records depreciation expense related to its plant by using the straight-line method over the plant’s useful life.  Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, for the years ended Dec. 31, 2008, 2007 and 2006 was 3.6 percent, 3.6 percent and 3.9 percent, respectively.

AFDC — AFDC represents the cost of capital used to finance utility construction activity.  AFDC is computed by applying a composite pretax rate to qualified construction work in progress.  The amount of AFDC capitalized as a utility construction cost is credited to nonoperating income (for equity capital) and interest charges (for debt capital).  AFDC amounts capitalized are included in NSP-Minnesota’s rate base for establishing utility service rates.  In addition to construction-related amounts, AFDC also is recorded to reflect returns on capital used to finance conservation programs in Minnesota.

Generally AFDC costs are recovered from customers, in future rates, as the related property is depreciated.  In 2003, the MPUC voted to approve NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants located in the Minneapolis-St. Paul metropolitan area to natural gas and to install advanced pollution control equipment at a third coal-fired plant.  These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW.  The first of these projects began operating in July 2007, the second of these projects began operating in June 2008 and the remaining projects are expected to begin operations in 2009, at a cumulative investment of approximately $1 billion.  The MPUC has approved a more current recovery of the financing costs related to the MERP.  The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFDC.

Decommissioning — NSP-Minnesota accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs.  The decommissioning calculation covers all expenses, including decontamination and removal of radioactive material and extends over the estimated lives of the plants.  The calculation assumes that NSP-Minnesota will recover those costs through rates.  The fair value of external nuclear decommissioning fund investments is determined based on quoted market prices for those or similar investments.  Unrealized gains or losses on the fund’s assets are included with regulatory assets on the consolidated balance sheets.  For more information on nuclear decommissioning, see Note 15 to the consolidated financial statements.

Nuclear Fuel Expense — Nuclear fuel expense, which is recorded as NSP-Minnesota’s nuclear generating plants use fuel, includes the cost of fuel used in the current period (including AFDC), as well as future disposal costs of spent nuclear fuel, costs associated with the end-of-life fuel segments and fees assessed by the DOE for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel enrichment facility.

Nuclear Refueling Outage Costs — Prior to the third quarter of 2008, NSP-Minnesota expensed the costs associated with refueling outages as incurred at its nuclear plants.  In September 2008, the MPUC authorized NSP-Minnesota to use a deferral and amortization method for the nuclear refueling operating and maintenance costs effective Jan. 1, 2008.  This method amortizes refueling outage costs over the period between refueling outages to better match revenues and expenses.

Environmental Costs — Environmental costs are recorded on an undiscounted basis when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated.  Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates.  Otherwise, the costs are expensed.  If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

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Estimated remediation costs, excluding inflationary increases, are recorded.  The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If several designated responsible parties exist, costs are estimated and recorded only for NSP-Minnesota’s expected share of the cost.  Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs — Litigation accruals are recorded when it is probable NSP-Minnesota is liable for the costs and the liability can be reasonably estimated.  External legal fees related to settlements are expensed as incurred.

Income Taxes — NSP-Minnesota accounts for income taxes using the asset and liability method under FAS 109, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements.  NSP-Minnesota defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  NSP-Minnesota uses the tax rates that are scheduled to be in effect when the temporary differences are expected to turn around, or reverse.  The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.  Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized.  In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences are accounted for as current income tax expense.  Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property.  Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are summarized in Note 16 to the consolidated financial statements.  For more information on income taxes, see Note 7 to the consolidated financial statements.

In July 2006, the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax positions that such company has taken or expects to take in its income tax returns.  FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date.  As required, NSP-Minnesota adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle.  The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material.  Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

NSP-Minnesota reports interest and penalties related to income taxes within the interest charges section in the consolidated statements of income.

Xcel Energy and its subsidiaries, including NSP- Minnesota, file consolidated federal income tax returns and combined and separate state income tax returns.  Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax.  Xcel Energy makes a similar allocation for state income taxes paid in connection with combined state filings.  The holding company also allocates its own net income tax benefits to its direct subsidiaries based on the positive tax liability of each company.

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Minnesota uses estimates based on the best information available.  Estimates are used for such items as plant depreciable lives, AROs, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs.  The recorded estimates are revised when better information becomes available or when actual amounts can be determined.  Those revisions can affect operating results.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

Cash and Cash Equivalents — NSP-Minnesota considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Restricted Cash — At Dec. 31, 2007, NSP-Minnesota had restricted cash of $8.4 million.  The restricted cash balance primarily represents margin deposits held in conjunction with short-term wholesale and commodity trading activities.  This balance is presented as a component of other investments on the consolidated balance sheets.

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Inventory — All inventory for NSP-Minnesota is recorded at average cost.

Regulatory Accounting — NSP-Minnesota accounts for certain income and expense items in accordance with SFAS No. 71– Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).  Under SFAS No. 71:

·Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover them in future rates; and

·Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be returned to customers in future rates.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item.  Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment.  If restructuring or other changes in the regulatory environment occur, NSP-Minnesota may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet.  Such changes could have a material effect on NSP-Minnesota’s results of operations in the period the write-off is recorded.  See more discussion of regulatory assets and liabilities at Note 16 to the consolidated financial statements.

Deferred Financing Costs — Other assets include deferred financing costs, net of amortization, of approximately $21.3 million and $18.2 million at Dec. 31, 2008 and 2007, respectively.  NSP-Minnesota is amortizing these financing costs over the remaining maturity periods of the related debt.

Debt premiums, discounts, expenses and amounts received or paid to settle hedges are amortized over the life of the related debt.  The premiums and costs associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.  If NSP-Minnesota extinguishes the debt, all unamortized balances shall be expensed at the time of the redemption.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of write-offs and an allowance for bad debts.  NSP-Minnesota establishes an allowance for uncollectible receivables based on a reserve policy that reflects its expected exposure to the credit risk of customers.

Renewable Energy Credits (RECs) — RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources.  RECs are awarded upon delivery of the associated energy and can be bought and sold.  RECs are typically used as a form of measurement of compliance to Renewable Portfolio Standards (RPS) enacted by those states that are encouraging construction and consumption of renewable energy, but can also be sold separately from the energy produced.  Currently, NSP-Minnesota acquires RECs from the generation or purchase of renewable power.

When RECs are acquired in the course of generation or purchase as a result of meeting the load obligation, they are recorded as inventory at actual cost.  RECs acquired for trading purposes are recorded as other investments at actual cost.  The cost of RECs that are retired for compliance purposes is recorded as electric fuel and purchased power expense.  The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues, net of any margin sharing requirements.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA.  NSP-Minnesota follows the inventory accounting model for all allowances.  The sales of allowances are reported in the operating activities section of the consolidated statements of cash flows.  The net margin on sales of emission allowances is included in electric utility operating revenues as it is integral to the production process of energy and our revenue optimization strategy for our utility operations.

Reclassifications — Conservation program expenses were reclassified as a separate item from other operating and maintenance expenses on the consolidated statements of income.  Activity from the allowance for bad debts was reclassified from the change in accounts receivable on the consolidated statements of cash flows. These reclassifications did not have an impact on total operating expenses or net cash provided by operating activities.

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2.Accounting Pronouncements

Recently Issued

Business Combinations (SFAS No. 141 (revised 2007)) — In December 2007, the FASB issued SFAS No. 141R, which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008.  NSP-Minnesota will apply SFAS No. 141R to business combinations occurring subsequent to Jan. 1, 2009.

Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51 (SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This statement is effective for fiscal years and interim periods beginning on or after Dec. 15, 2008.  NSP-Minnesota does not expect the implementation of SFAS No. 160 to have a material impact on its consolidated financial statements.

Disclosures about Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133 (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative agreements.  SFAS No. 161 is effective for fiscal years and interim periods beginning after Nov. 15, 2008, with early application encouraged.  NSP-Minnesota does not expect the implementation of SFAS No. 161 to have a material impact on its consolidated financial statements.

Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) — In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand on an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk.  FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009.  NSP-Minnesota does not expect that implementation of FSP FAS 132(R)-1 to have a material impact on its consolidated financial statements.

Recently Adopted

Fair Value Measurements (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities.  SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets.  Fair value measurements are disclosed by level within that hierarchy.  SFAS No. 157 was effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.

On Jan. 1, 2008, NSP-Minnesota adopted SFAS No. 157 for all assets and liabilities measured at fair value except for non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis, as permitted by FSP FAS 157-2, Effective Date of FASB Statement No. 157.  The adoption did not have a material impact on NSP-Minnesota’s consolidated financial statements.  For additional discussion and SFAS No. 157 required disclosures, see Note 12 to the consolidated financial statements.

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The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (SFAS No. 159) — In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value.  A company that adopts SFAS No. 159 will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date.  This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  This statement was effective for fiscal years beginning after Nov. 15, 2007.  NSP-Minnesota adopted SFAS No. 159 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Determining the Fair Value of a Financial Asset When the Market for That Asset is Not Active  (FSP FAS 157-3) — In October 2008, the FASB issued FSP FAS 157-3, which clarifies the application of SFAS No. 157 in a market that is not active.  FSP FAS 157-3 was effective immediately upon issuance, and applied to prior periods for which financial statements had not yet been issued.  NSP-Minnesota adopted FSP FAS 157-3 as of Sept. 30, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements (Emerging Issues Task Force (EITF) Issue No. 06-4) — In June 2006, the EITF reached a consensus on EITF No. 06-4, which provides guidance on the recognition of a liability and related compensation costs for endorsement split-dollar life insurance policies that provide a benefit to an employee that extends to postretirement periods.  Therefore, this EITF would not apply to a split-dollar life insurance arrangement that provides a specified benefit to an employee that is limited to the employee’s active service period with an employer.  EITF No. 06-4 was effective for fiscal years beginning after Dec. 15, 2007, with earlier application permitted.  Upon adoption of EITF No. 06-4 on Jan. 1, 2008, NSP-Minnesota recorded a liability of $0.6 million, net of tax, as a reduction of retained earnings.  Thereafter, changes in the liability are reflected in operating results.

Amendment of FASB Interpretation No. 39 (FSP FIN 39-1) — In April 2007, the FASB issued FSP FIN 39-1, which amends FIN 39, Offsetting of Amounts Related to Certain Contracts, to permit companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement.  FSP FIN 39-1 was effective for fiscal years beginning after Nov. 15, 2007.  NSP-Minnesota adopted FSP FIN 39-1 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11) — In June 2007, the EITF reached a consensus on EITF No. 06-11, which states that an entity should recognize a realized tax benefit associated with dividends on nonvested equity shares and nonvested equity share units charged to retained earnings as an increase in additional paid in capital.  The amount recognized in additional paid in capital should be included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards.  EITF No. 06-11 was to be applied prospectively to income tax benefits of dividends on equity-classified share-based payment awards that were declared in fiscal years beginning after Dec. 15, 2007.  NSP-Minnesota adopted EITF No. 06-11 on Jan. 1, 2008, and the adoption did not have a material impact on its consolidated financial statements.

The Hierarchy of GAAP (SFAS No. 162) — In May 2008, the FASB issued SFAS No. 162, which establishes the GAAP hierarchy, identifying the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements.  SFAS No. 162 was effective Nov. 15, 2008.  NSP-Minnesota adopted SFAS No. 162 on Dec. 31, 2008, and the adoption did not have a material impact on its consolidated financial statements.

Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities (FSP FAS 140-4 and FIN 46(R)-8) — In December 2008, the FASB issued FSP FAS 140-4 and FIN 46(R)-8, which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, to require public entities to provide additional disclosures about transfers of financial assets.  It also amends FIN 46 (revised December 2003), Consolidation of Variable Interest Entities, to require public enterprises, including sponsors that have a variable interest in a variable interest entity, to provide additional disclosures about their involvement with variable interest entities.  FSP FAS 140-4 and FIN 46(R)-8 was effective for the interim and annual periods ending after Dec. 15, 2008.  NSP-Minnesota adopted FSP FAS 140-4 and FIN 46(R)-8 on Dec. 31, 2008, and the adoption did not have a material impact on its consolidated financial statements.

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3.Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2008			Dec. 31, 2007
Accounts receivable, net:
Accounts receivable	$	438,855		$	462,033
Less allowance for bad debts	(25,699		)	(20,103		)
	$	413,156		$	441,930
Inventories:
Materials and supplies	$	97,945		$	93,853
Fuel	141,190			77,257
Natural gas	106,768			99,528
	$	345,903		$	270,638
Property, plant and equipment, net:
Electric utility plant	$	9,472,073		$	8,855,144
Natural gas utility plant	916,740			890,371
Construction work in progress	615,734			818,276
Common utility and other property	452,308			447,527
Total property, plant and equipment	11,456,855			11,011,318
Less accumulated depreciation	(4,907,681		)	(4,708,496		)
Nuclear fuel	1,611,193			1,471,229
Less accumulated amortization	(1,355,573		)	(1,291,370		)
	$	6,804,794		$	6,482,681

4.Short-Term Borrowings

Commercial Paper — At Dec. 31, 2008 and 2007, NSP-Minnesota had commercial paper outstanding of $65.0 million and $341.5 million, respectively.  NSP-Minnesota has board approval to issue up to $500 million of commercial paper.  The weighted average interest rates at Dec. 31, 2008 and 2007, were 2.57 percent and 5.58 percent, respectively.

Money Pool — Xcel Energy and its utility subsidiaries have established a utility money pool arrangement that allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates.  The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company.  NSP-Minnesota has approval to borrow up to $250 million under the arrangement.  At Dec. 31, 2008 and 2007, NSP-Minnesota had money pool borrowings of $63.5 million and $95.1 million, respectively.  The weighted average interest rates at Dec. 31, 2008 and 2007, were 3.48 percent and 5.64 percent, respectively.

5.Long-Term Debt

Credit Facilities — At Dec. 31, 2008, NSP-Minnesota had the following committed credit facility in effect, in millions of dollars:

Credit Facility		Credit Facility Borrowings		Available*		Original Term	Maturity
$	482.2	$	—	$	411.4	Five year	December 2011

* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.  NSP-Minnesota has the right to request an extension of the final maturity date by one year.  The maturity extension is subject to majority bank group approval.

·The credit facility has one financial covenant requiring that NSP-Minnesota’s debt-to-total capitalization ratio be less than or equal to 65 percent with which NSP-Minnesota was in compliance at Dec. 31, 2008 and 2007.  If NSP-Minnesota

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does not comply with the covenant, it is deemed an event of default and any outstanding amounts due under the facility can be declared due by the lender.

·The credit facility has a cross default provision that provides the borrower will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets, defaults on any of its indebtedness greater than $50 million.

·The interest rate is based on either the agent bank’s prime rate or the applicable LIBOR, plus a borrowing margin as based on NSP-Minnesota’s senior unsecured credit ratings from Moody, Standard & Poor and Fitch.  The commitment fees are calculated for the unused portion of the credit facility at 6 basis points for NSP-Minnesota.

·At Dec. 31, 2008, NSP-Minnesota had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $65.0 million of commercial paper outstanding and $5.8 million of letters of credit.

·At Dec. 31, 2007, NSP-Minnesota had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $341.5 million of commercial paper outstanding and $6.1 million of letters of credit.

Long-Term Borrowings

On March 18, 2008, NSP-Minnesota issued $500 million of 5.25 percent first mortgage bonds, series due March 1, 2018.  NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper and borrowings under the utility money pool arrangement.

On Aug. 1, 2007, NSP-Minnesota redeemed all of its outstanding 8.00 percent Notes, series due 2042, at a redemption price equal to 100 percent of the principal amount of the notes ($25.00), plus accrued and unpaid interest on the notes, if any, to the redemption date.  Upon redemption, Xcel Energy recognized approximately $9.3 million in interest expense due to unwinding a fair value interest rate derivative.

On June 26, 2007, NSP-Minnesota issued $350 million of 6.20 percent first mortgage bonds, series due July 1, 2037.  NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper.

All property of NSP-Minnesota is subject to the lien of its first mortgage indenture.  NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay Xcel Energy, the holder of its common stock.  Even with these restrictions, NSP-Minnesota could have paid more than $999 million and $946 million in additional cash dividends on common stock at Dec. 31, 2008 and 2007, respectively.

Maturities of long-term debt are:

(Millions of Dollars)
2009	$	250.1
2010	175.0
2011	—
2012	450.0
2013	—

6.Joint Plant Ownership

Following are the investments by NSP-Minnesota in jointly owned plants and the related ownership percentages as of Dec. 31, 2008:

(Thousands of Dollars)	Plant in Service		Accumulated Depreciation		Construction Work in Progress		Ownership%
Sherco Unit 3	$	527,647	$	325,472	$	128	59.0
Sherco Common Facilities Units 1, 2 & 3	122,812		73,779		180		75.0
Transmission facilities, including substations	4,790		2,231		—		59.0
Total	$	655,249	$	401,482	$	308

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NSP-Minnesota is part owner of Sherco 3, an 860 MW, coal-fueled electric generating unit.  NSP-Minnesota is the operating agent under the joint ownership agreement.  NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable utility accounts.  Each of the respective owners is responsible for funding its portion of construction and operating costs.

Nuclear Plant Operation — On Sept. 28, 2007, NSP-Minnesota obtained 100 percent ownership in NMC as a result of Wisconsin Energy Corporation (WEC), exiting the partnership due to the sale of its Point Beach Nuclear Plant to FPL Energy.  Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota’s consolidated financial statements from the Sept. 28, 2007, transaction date.  WEC was required to pay an exit fee and surrender all of its equity interest in NMC upon exiting.  The effect of this transaction was not material to the financial position or the results of operations to NSP-Minnesota for the year ended Dec. 31, 2007.  NSP-Minnesota has reintegrated its nuclear operations into its generation operations.  The NRC transferred the nuclear operating licenses from NMC to NSP-Minnesota effective Sept. 22, 2008.

7.Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated income tax returns.  In the first quarter of 2008, the IRS completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003).  The IRS did not propose any material adjustments for those tax years.  Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009.  In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007.  As of Dec. 31, 2008, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

In the first quarter of 2008, the state of Minnesota concluded an income tax audit through tax year 2001.  No material adjustments were proposed for this audit.  As of Dec. 31, 2008, NSP-Minnesota’s earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004.  There currently are no state income tax audits in progress.

The amount of unrecognized tax benefits reported was $14.3 million and $20.2 million on Dec. 31, 2007 and 2008, respectively.  A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	2008			2007
Balance at Jan. 1	$	14.3		$	22.5
Additions based on tax positions related to the current year	5.4			5.6
Reductions based on tax positions related to the current year	(0.4		)	(0.2		)
Additions for tax positions of prior years	4.9			8.4
Reductions for tax positions of prior years	—			(3.4		)
Settlements with taxing authorities	(4.0		)	(18.6		)
Balance at Dec. 31	$	20.2		$	14.3

These unrecognized tax benefit amounts were reduced by the tax benefits associated with tax credit carryovers of $2.2 million and $4.4 million as of Dec. 31, 2007 and 2008, respectively.

The unrecognized tax benefit balance included $6.6 million and $7.2 million of tax positions on Dec. 31, 2007 and 2008, respectively, which if recognized would affect the annual effective tax rate.  In addition, the unrecognized tax benefit balance included $7.7 million and $13.0 million of tax positions on Dec. 31, 2007 and 2008, respectively, for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility.  A change in the period of deductibility would not affect the effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The increase in the unrecognized tax benefit balance of $5.9 million from Dec. 31, 2007 to Dec. 31, 2008, was due to the addition of similar uncertain tax positions related to ongoing activity.  NSP-Minnesota’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when state audits resume.  At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

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The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with tax credit carryovers.  The amount of interest income related to unrecognized tax benefits reported within interest charges was $0.6 million for both 2007 and 2008.  The liability for interest related to unrecognized tax benefits was $1.9 million and $1.3 million on Dec. 31, 2007 and 2008, respectively.  No amounts were accrued for penalties as of Dec. 31, 2007 and 2008.

Other Income Tax Matters — NSP-Minnesota’s federal net operating loss carryforward is estimated to be $22.1 million and $20.6 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively.  NSP-Minnesota’s federal tax credit carryforward is estimated to be $14.8 million and $11.9 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively.  The carryforward periods expire between 2021 and 2028.  NSP-Minnesota also has state tax credit carryforwards of $1.6 million and $1.3 million as of Dec. 31, 2008 and Dec. 31, 2007, respectively.  The state carryforward periods expire between 2018 and 2027.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense.  The following is a table reconciling such differences for the years ending Dec. 31:

	2008		2007		2006
Federal statutory rate	35.0	%	35.0	%	35.0	%
Increases (decreases) in tax from:
State income taxes, net of federal income tax benefit	7.6		8.4		3.6
Resolution of income tax audits and other	—		0.4		(2.5	)
Tax credits recognized, net of federal income tax expense	(1.6	)	(1.5	)	(2.0	)
Regulatory differences — utility plant items	(2.3	)	(1.7	)	(1.6	)
Life insurance policies	(0.2	)	(0.2	)	(0.2	)
FIN 48 expense – unrecognized tax benefits	0.1		0.2		—
Other, net	(0.1	)	(0.1	)	(0.4	)
Effective income tax rate	38.5	%	40.5	%	31.9	%

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2008			2007			2006
Current federal tax expense	$	9,527		$	15,277		$	178,668
Current state tax expense	27,802			4,987			37,145
Current FIN 48 tax expense (benefit)	3,709			(6,346		)	—
Deferred federal tax expense (benefit)	122,485			117,433			(66,226		)
Deferred state tax expense (benefit)	25,653			50,151			(13,752		)
Deferred FIN 48 tax (benefit) expense	(3,106		)	7,416			—
Deferred tax credits	(4,331		)	(2,996		)	(3,383		)
Deferred investment tax credits	(3,503		)	(3,897		)	(4,846		)
Total income tax expense	$	178,236		$	182,025		$	127,606

The components of deferred income tax at Dec. 31 were:

(Thousands of Dollars)	2008		2007
Deferred tax expense excluding items below	$	80,493	$	185,214
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	55,322		(26,444		)
FIN 48 adoption: Deferred tax expense reported as an adjustment to the beginning balance of retained earnings	—		13,981
Tax expense (benefit) allocated to other comprehensive income and other	4,886		(747		)
Deferred tax expense	$	140,701	$	172,004

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The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

(Thousands of Dollars)	2008		2007
Deferred tax liabilities:
Differences between book and tax bases of property	$	1,003,706	$	905,225
Regulatory assets	81,411		74,831
Deferred costs	9,211		14,135
Unbilled revenues	6,342		9,934
Other	17,083		19,079
Total deferred tax liabilities	$	1,117,753	$	1,023,204
Deferred tax assets:
Employee benefits	$	62,410	$	71,314
Deferred investment tax credits	16,443		17,872
Regulatory liabilities	12,927		15,013
Tax credit carry forward	16,392		13,141
Bad debts	10,497		8,211
Rate refund	19,144		6,710
Net operating loss carry forward	6,790		3,358
Other	11,198		6,126
Total deferred tax assets	$	155,801	$	141,745
Net deferred tax liability	$	961,952	$	881,459

8.    Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to NSP-Minnesota.

Xcel Energy offers various benefit plans to its employees, including those of NSP-Minnesota.  Approximately 50 percent of Xcel Energy employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements.  At Dec. 31, 2008, NSP-Minnesota had 2,279 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2010.  NSP-Minnesota also had an additional 209 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates through September 2010.

Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R) (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income.  NSP-Minnesota applied regulatory accounting treatment for unrecognized amounts of regulated utility subsidiary employees, which allowed recognition as a regulatory liability reduction rather than as a charge to accumulated other comprehensive income.  The effect of adopting in 2006 for the remaining unrecognized amounts was a decrease in accumulated other comprehensive income of $3.2 million.

Pension Benefits

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees.  Benefits are based on a combination of years of service, the employee’s average pay and Social Security benefits.

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets — Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government securities.  The target range for our pension asset allocation is 52 percent in equity investments, 25 percent in fixed income investments and 23 percent in nontraditional investments, such as real estate, private equity and a diversified commodities index.

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The actual composition of pension plan assets at Dec. 31 was:

	2008		2007
Equity securities	55	%	60	%
Debt securities	26		22
Real estate	5		4
Cash	3		2
Nontraditional investments	11		12
	100	%	100	%

Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension asset portfolio.  Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts.  The historical weighted average annual return for the past 20 years for the Xcel Energy portfolio of pension investments is 9.56 percent, which is greater than the current assumption level.  The pension cost determination assumes the continued current mix of investment types over the long term.  The Xcel Energy portfolio is heavily weighted toward equity securities and includes nontraditional investments.  A higher weighting in equity investments can increase the volatility in the return levels achieved by pension assets in any year.  Investment returns in 2008 and 2007 were below the assumed level of 8.75 percent while returns in 2006 exceeded the assumed level of 8.75 percent.  Xcel Energy continually reviews its pension assumptions.  In 2009, Xcel Energy will use an investment-return assumption of 8.50 percent.

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:

(Thousands of Dollars)	2008			2007
Accumulated Benefit Obligation at Dec. 31	$	2,435,513		$	2,497,898
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,662,759		$	2,666,555
Service cost	62,698			61,392
Interest cost	167,881			162,774
Plan amendments	—			(19,955		)
Actuarial (gain) loss	(47,509		)	23,325
Benefit payments	(247,797		)	(231,332		)
Obligation at Dec. 31	$	2,598,032		$	2,662,759
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	3,186,273		$	3,183,375
Actual (loss) return on plan assets	(788,273		)	199,230
Employer contributions	35,000			35,000
Benefit payments	(247,797		)	(231,332		)
Fair value of plan assets at Dec. 31	$	2,185,203		$	3,186,273
Funded Status of Plans at Dec. 31:
Funded Status	$	(412,829	)	$	523,514
Noncurrent assets	15,612			568,055
Noncurrent liabilities	(428,441		)	(44,541		)
Net pension amounts recognized on consolidated balance sheets	$	(412,829	)	$	523,514
NSP-Minnesota accrued benefit liability recorded	$	91,095		$	—
NSP-Minnesota prepaid pension asset recorded	—			270,436

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(Thousands of Dollars)	2008		2007
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	454,770	$	72,479
Prior service cost	46,222		57,948
Total	$	500,992	$	130,427
SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	500,992	$	—
Regulatory liabilities	—		130,427
Total	$	500,992	$	130,427

Measurement Date	Dec. 31, 2008			Dec. 31, 2007
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		6.75	%		6.25	%
Expected average long-term increase in compensation level		4.00			4.00
Mortality table	RP	2000		RP	2000

At Dec. 31, 2008, one of Xcel Energy’s pension plans had plan assets of $259.9 million, which exceeded projected benefit obligations of $244.3 million.  At Dec. 31, 2007, the plan assets of $369.8 million exceeded projected benefit obligations of $253.6 million.  All other Xcel Energy plans in the aggregate had plan assets of $1.9 billion and $2.8 billion and projected benefit obligations of $2.4 billion and $2.4 billion on Dec. 31, 2008 and 2007.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations.  These regulations did not require cash funding for 2006 through 2008 for Xcel Energy’s pension plans and are not expected to require cash funding in 2009.

·Voluntary contributions were made to the PSCo Bargaining Pension Plan of $35 million in 2008, $35 million in 2007 and $30 million in 2006.

·Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $2 million in 2006.  No voluntary contributions were made to the plan during 2007 or 2008.

·Xcel Energy projects cash funding of $70 million to $130 million in 2009.  Pension funding contributions for 2010, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $150 million to $250 million.

Plan Changes — The Pension Protection Act of 2006 (PPA) was effective Dec. 31, 2006.  PPA requires a change in the conversion basis for lump-sum payments and three-year vesting for plans with account balance or pension equity benefits.  These changes are reflected as a plan amendment for purposes of SFAS No. 87, Employers’ Accounting for Pensions.

Benefit Costs — The components of net periodic pension cost (credit) are:

(Thousands of Dollars)	2008			2007			2006
Service cost	$	62,698		$	61,392		$	61,627
Interest cost	167,881			162,774			155,413
Expected return on plan assets	(274,338		)	(264,831		)	(268,065		)
Amortization of prior service cost	20,584			25,056			29,696
Amortization of net loss	11,156			15,845			17,353
Net periodic pension (credit) cost under SFAS No. 87	$	(12,019	)	$	236		$	(3,976	)
NSP-Minnesota:
Net periodic pension credit	$	(9,034	)	$	(9,682	)	$	(11,373	)
Credits not recognized due to effects of regulation	9,034			11,147			12,637
Net benefit cost recognized for financial reporting	$	—		$	1,465		$	1,264
Significant Assumptions Used to Measure Costs:
Discount rate	6.25		%	6.00		%	5.75		%
Expected average long-term increase in compensation level	4.00			4.00			3.50
Expected average long-term rate of return on assets	8.75			8.75			8.75

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Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan.  The return assumption used for 2009 pension cost calculations will be 8.50 percent.  The cost calculation uses a market-related valuation of pension assets.  Xcel Energy uses a calculated value method to determine the market-related value of the plan assets.  The market-related value begins with the fair market value of assets as of the beginning of the year.  The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel.  Benefits for these unfunded plans are paid out of their operating cash flows.

Defined Contribution Plans

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees.  The contributions for NSP-Minnesota were approximately $4.2 million in 2008 and 2007 and $3.9 million in 2006.

Postretirement Health Care Benefits

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees.  The former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999.  Employees of the former NSP who retired after 1998 are eligible to participate in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106 — Employers’ Accounting for Postretirement Benefits Other Than Pension, Xcel Energy elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs under SFAS No. 106.  NSP-Minnesota transitioned to full accrual accounting for SFAS No. 106 costs, with regulatory differences fully amortized prior to 1997.

Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of SFAS No. 106 costs.  Also, a portion of the assets contributed on behalf of non-bargaining retirees has been funded into a sub-account of the Xcel Energy pension plans.  These assets are invested in a manner consistent with the investment strategy for the pension plan.

The actual composition of postretirement benefit plan assets at Dec. 31 was:

	2008		2007
Equity and equity mutual fund securities	49	%	67	%
Fixed income/debt securities	29		21
Cash equivalents	22		11
Nontraditional investments	—		1
	100	%	100	%

Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in its postretirement health care asset portfolio.  Investment-return volatility is not considered to be a material factor in postretirement health care costs.

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health care plans that benefit employees of its utility subsidiaries is presented in the following table:

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(Thousands of Dollars)	2008			2007
Change in Benefit Obligation:
Obligation at Jan. 1	$	830,315		$	918,693
Service cost	5,350			5,813
Interest cost	51,047			50,475
Medicare subsidy reimbursements	6,178			2,526
Plan participants’ contributions	13,892			13,211
Actuarial gain	(46,827		)	(86,576		)
Benefit payments	(65,358		)	(73,827		)
Obligation at Dec. 31	$	794,597		$	830,315

(Thousands of Dollars)	2008			2007
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	427,459		$	406,305
Actual (loss) return on plan assets	(132,226		)	24,623
Plan participants’ contributions	13,892			13,211
Employer contributions	55,799			57,147
Benefit payments	(65,358		)	(73,827		)
Fair value of plan assets at Dec. 31	$	299,566		$	427,459
Funded Status at Dec. 31:
Funded status	$	(495,031	)	$	(402,856	)
Current liabilities	(4,928		)	(1,755		)
Noncurrent liabilities	(490,103		)	(401,101		)
Net amounts recognized in consolidated balance sheets	$	(495,031	)	$	(402,856	)
NSP-Minnesota Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	78,140		$	88,968
Transition obligation	5,419			6,765
Total	$	83,559		$	95,733
SFAS No. 158 Amounts Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	80,105		$	—
Regulatory liabilities	—			91,757
Deferred income taxes	1,411			1,624
Net-of-tax accumulated other comprehensive income	2,043			2,352
Total	$	83,559		$	95,733
NSP-Minnesota accrued benefit liability recorded	$	152,792		$	164,405

Measurement Date	Dec. 31, 2008			Dec. 31, 2007
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation	6.75		%	6.25		%
Mortality table	RP	2000		RP	2000

Effective Dec. 31, 2008, Xcel Energy reduced its initial medical trend assumption from 8.0 percent to 7.4 percent.  The ultimate trend assumption remained unchanged at 5.0 percent.  The period until the ultimate rate is reached is five years.  Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

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A 1-percent change in the assumed health care cost trend rate would have the following effects on NSP-Minnesota:

(Thousands of Dollars)
1-percent increase in APBO components at Dec. 31, 2008	$	16,627
1-percent decrease in APBO components at Dec. 31, 2008	(14,031		)
1-percent increase in service and interest components of the net periodic cost	1,389
1-percent decrease in service and interest components of the net periodic cost	(1,146		)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans.  Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously.  Xcel Energy contributed $55.6 million during 2008 and expects to contribute approximately $63.1 million during 2009.

Benefit Costs — The components of net periodic postretirement benefit cost are:

(Thousands of Dollars)	2008			2007			2006
Service cost	$	5,350		$	5,813		$	6,633
Interest cost	51,047			50,475			52,939
Expected return on plan assets	(31,851		)	(30,401		)	(26,757		)
Amortization of transition obligation	14,577			14,577			14,444
Amortization of prior service credit	(2,175		)	(2,178		)	(2,178		)
Amortization of net loss	11,498			14,198			24,797
Net periodic postretirement benefit cost under SFAS No. 106	$	48,446		$	52,484		$	69,878
NSP-Minnesota:
Net periodic postretirement benefit cost recognized — SFAS No. 106	$	13,958		$	13,761		$	17,154
Significant assumptions used to measure costs (income):
Discount rate	6.25		%	6.00		%	5.75		%
Expected average long-term rate of return on assets (before tax)	7.50			7.50			7.50

Projected Benefit Payments

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans.

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2009	$	224,558	$	62,975	$	5,725	$	57,250
2010	226,585		64,468		6,117		58,351
2011	226,446		66,390		6,433		59,957
2012	230,763		67,400		6,804		60,596
2013	234,149		68,008		7,127		60,881
2014-2018	1,237,114		351,249		38,796		312,453

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9.Detail of Interest and Other Income (Expense), Net

Interest and other income, net of nonoperating expenses, for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2008			2007			2006
Interest income	$	10,005		$	10,208		$	13,294
Equity income in unconsolidated affiliates	—			770			1,312
Other nonoperating income	1,274			1,048			945
Insurance policy expenses	(384		)	(5,921		)	(6,120		)
Total interest and other income, net	$	10,895		$	6,105		$	9,431

10.Derivative Instruments

In the normal course of business, NSP-Minnesota is exposed to a variety of market risks.  Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity.  NSP-Minnesota utilizes, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance its operations.

Commodity Price Risk — NSP-Minnesota is exposed to commodity price risk in its electric and natural gas operations.  Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used for generation and distribution activities.  Commodity risk is also managed through the use of financial derivative instruments.  NSP-Minnesota utilizes these derivative instruments to reduce the volatility in the cost of commodities acquired on behalf of its retail customers even though the regulatory jurisdiction may provide for recovery of actual costs.  NSP-Minnesota’s risk-management policy allows it to manage commodity price risk within each rate-regulated operation to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — NSP-Minnesota conducts various short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  NSP-Minnesota’s risk-management policy allows management to conduct these activities within guidelines and limitations as approved by the risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Interest Rate Risk — NSP-Minnesota is subject to the risk of fluctuating interest rates in the normal course of business.  NSP-Minnesota’s risk-management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options, subject to regulatory approval when required.

Types of and Accounting for Derivative Instruments

NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price, vehicle fuel price, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, are recorded on the consolidated balance sheets at fair value as derivative instruments valuation.  This includes certain instruments used to mitigate market risk for NSP-Minnesota and all instruments related to the commodity trading operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualified hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification is dependent on the applicability of specific regulation.

Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge).  The types of qualifying hedging transactions that NSP-Minnesota is currently engaged in are discussed below.

Cash Flow Hedges

Commodity Cash Flow Hedges — NSP-Minnesota enters into derivative instruments to manage variability of future cash flows from changes in commodity prices.  This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale, and vehicle fuel.  Certain derivative instruments entered into to manage this variability are designated as cash flow hedges for accounting purposes.  At Dec. 31, 2008, NSP-Minnesota had various

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commodity-related contracts designated as cash flow hedges extending through December 2010.  Changes in the fair value of cash flow hedges are recorded in other comprehensive income or deferred as a regulatory asset or liability.  This classification is based on the regulatory recovery mechanisms in place.

At Dec. 31, 2008, NSP-Minnesota had $6.6 million of net losses in accumulated other comprehensive income related to commodity cash flow hedge contracts; $3.9 million is expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

NSP-Minnesota had immaterial ineffectiveness related to commodity cash flow hedges during 2008 and 2007.

Interest Rate Cash Flow Hedges — NSP-Minnesota enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period.  These derivative instruments are designated as cash flow hedges for accounting purposes.

At Dec. 31, 2008, NSP-Minnesota had net gains of approximately $0.1 million in accumulated other comprehensive income related to interest rate hedges that it expects to recognize in earnings during the next 12 months.

NSP-Minnesota had no ineffectiveness related to interest rate cash flow hedges during 2008 and 2007.

The following table shows the major components of the derivative instruments valuation in the consolidated balance sheets at Dec. 31:

	2008				2007
(Thousands of Dollars)	Derivative Instruments Valuation – Assets		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities
Long term purchased power agreements	$	151,884	$	230,715	$	176,443	$	245,240
Electricity and natural gas trading and hedging instruments	47,973		28,522		31,765		12,176
Interest rate hedging instruments	—		—		—		2,727
Total	$	199,857	$	259,237	$	208,208	$	260,143

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, NSP-Minnesota began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During the first quarter of 2006, NSP-Minnesota qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying cash flow hedges on NSP-Minnesota’s accumulated other comprehensive income, included in the consolidated statements of common stockholder’s equity and comprehensive income, is detailed in the following table:

(Millions of Dollars)
Accumulated other comprehensive income related to hedges at Dec. 31, 2005	$	—
After-tax net unrealized gains related to derivatives accounted for as hedges	9.6
After-tax net realized gains on derivative transactions reclassified into earnings	(0.2		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2006	$	9.4
After-tax net unrealized losses related to derivatives accounted for as hedges	(0.3		)
After-tax net realized gains on derivative transactions reclassified into earnings	(0.4		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2007	$	8.7
After-tax net unrealized losses related to derivatives accounted for as hedges	(5.5		)
After-tax net realized gains on derivative transactions reclassified into earnings	(0.2		)
Accumulated other comprehensive income related to hedges at Dec. 31, 2008	$	3.0

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11.Financial Instruments

The estimated Dec. 31 fair values of NSP-Minnesota’s recorded financial instruments are as follows:

	2008				2007
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Nuclear decommissioning fund	$	1,075,294	$	1,075,294	$	1,317,564	$	1,317,564
Other investments	725		725		9,154		9,154
Long-term debt, including current portion	2,962,749		3,100,223		2,463,109		2,628,580

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts.  The fair value of NSP-Minnesota’s nuclear decommissioning fund is based on published trading data and pricing models, generally using the most observable inputs available for each class of security.  The fair value of NSP-Minnesota’s other investments are estimated based on quoted market prices for those or similar investments.  The fair value of NSP-Minnesota’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2008 and 2007.  These fair value estimates have not been comprehensively revalued for purposes of these consolidated financial statements since that date, and current estimates of fair values may differ significantly.

All unrealized gains and losses in the external decommissioning fund are recorded as a regulatory asset or liability pursuant to SFAS No. 71.  The following tables provide the external decommissioning fund’s approximate gains, losses and proceeds from the sale of securities for the years ended Dec. 31:

(Thousands of Dollars)	2008		2007		2006
Realized gains	$	65,779	$	38,745	$	310,066
Realized losses	107,272		35,794		32,412
Proceeds from sale of securities	914,514		669,070		958,294

Letters of Credit

NSP-Minnesota uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At Dec. 31, 2008 and 2007, there were $6.9 million and $7.2 million of letters of credit outstanding.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

12.Fair Value Measurements

Effective Jan. 1, 2008, NSP-Minnesota adopted SFAS No. 157 for recurring fair value measurements.  SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value.  SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value.  The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reported date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of FTRs.

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NSP-Minnesota continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment, as well an assessment of the impact of NSP-Minnesota’s own credit risk when determining the fair value of commodity derivative liabilities, the impact of considering credit risk was immaterial to the fair value of commodity derivative assets and liabilities at Dec. 31, 2008.

The following table presents, for each of these hierarchy levels, NSP-Minnesota’s assets and liabilities that are measured at fair value on a recurring basis as of Dec. 31, 2008:

(Thousands of Dollars)	Level 1		Level 2		Level 3		Counterparty  Netting (a)			Net Balance
Assets:
Nuclear decommissioning fund	$	465,936	$	499,935	$	109,423	$	—		$	1,075,294
Commodity derivatives	—		17,039		38,207		(7,273		)	47,973
Total	$	465,936	$	516,974	$	147,630	$	(7,273	)	$	1,123,267
Liabilities:
Commodity derivatives	$	—	$	21,509	$	14,960	$	(7,947	)	$	28,522
Total	$	—	$	21,509	$	14,960	$	(7,947	)	$	28,522

(a) FASB Interpretation No. 39 Offsetting of Amounts Relating to Certain Contracts, as amended by FASB Staff Position FIN 39-1 Amendment of FASB Interpretation No. 39, permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between NSP-Minnesota and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

The following table presents the changes in Level 3 recurring fair value measurements for the year ended Dec. 31, 2008:

(Thousands of Dollars)	Commodity Derivatives, Net			Nuclear Decommissioning Fund
Balance Jan. 1, 2008	$	15,345		$	108,656
Purchases, issuances, and settlements, net	(1,585		)	12,198
Transfers out of Level 3	(2,578		)	—
Gains recognized in earnings	496			—
Gains (losses) recognized as regulatory assets and liabilities	11,569			(11,431		)
Balance Dec. 31, 2008	$	23,247		$	109,423

Gains on Level 3 commodity derivatives recognized in earnings for the year ended Dec. 31, 2008, include $2.9 million of net unrealized gains relating to commodity derivatives held at Dec. 31, 2008.  Realized and unrealized gains and losses on commodity trading activities are included in electric revenues.  Realized and unrealized gains and losses on short-term wholesale activities reflect the impact of regulatory recovery and are deferred as regulatory assets and liabilities.  Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a component of a nuclear decommissioning regulatory asset.

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13.Rate Matters

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — MPUC

Base Rate

NSP-Minnesota Electric Rate Case — On Nov. 3, 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually, or 6.05 percent.  The request is based on a 2009 forecast test year, an electric rate base of $4.1 billion, a requested ROE of 11.0 percent and an equity ratio of 52.5 percent.

In December 2008, the MPUC approved an interim rate increase of $132 million, or 5.12 percent, effective Jan. 2, 2009.  The primary difference between interim rate levels approved and NSP-Minnesota’s request of $156 million is due to a previously authorized ROE of 10.54 percent and NSP-Minnesota’s requested ROE of 11.0 percent.

A final decision from the MPUC is expected in the third quarter of 2009.  The following procedural schedule has been established:

·Staff and intervenor direct testimony on April 7, 2009;

·NSP-Minnesota rebuttal testimony on May 5, 2009;

·Staff and intervenor surrebuttal testimony on May 26, 2009; and

·Evidentiary hearings are scheduled for June 2-9, 2009.

Electric, Purchased Gas and Resource Adjustment Clauses

TCR Rider — In November 2006, the MPUC approved a TCR rider pursuant to legislation, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases.  In December 2007, NSP-Minnesota filed adjustments to the TCR rate factors and implemented a rider to recover $18.5 million beginning Jan. 1, 2008.  In March 2008, the MPUC approved the 2008 rider, but required certain procedural changes for future TCR filings if costs are disputed.  On Oct. 30, 2008, NSP-Minnesota submitted its proposed TCR rate factors for proposed recovery in 2009, seeking to recover $14 million beginning Jan. 1, 2009.  A portion of amounts previously collected through the TCR rider prior to 2009 has been included for recovery in the electric rate case described above.  MPUC approval is pending.

RES Rider — In March 2008, the MPUC approved an RES rider to recover the costs for utility-owned projects implemented in compliance with the RES, and the RES rider was implemented on April 1, 2008.  Under the rider, NSP-Minnesota could recover up to approximately $14.5 million in 2008 attributable to the Grand Meadow wind farm, a 100 MW wind project, subject to true-up.  In 2008, NSP-Minnesota submitted the RES rider for recovery of approximately $22 million in 2009 attributable to the Grand Meadow wind farm.  On Feb. 12, 2009, the MPUC approved the rider request but required that the issue of whether these costs should be moved to base rates in the currently pending electric rate case or left in the rider, as NSP-Minnesota has proposed, to be addressed through supplemental testimony in the rate case.

MERP Rider — On Oct. 1, 2008, NSP-Minnesota filed a proposed MERP rider for 2009 designed to recover costs related to MERP environmental improvement projects.  Under this rider, NSP-Minnesota proposes to recover $114 million in 2009, an increase of approximately $23 million over 2008.  New rates went into effect automatically on Jan. 1, 2009 as stipulated.  MPUC approval is still pending.

Annual Automatic Adjustment Report for 2007 — In September 2007, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2006 through June 30, 2007, which is the basis for the MPUC review of charges that flow through the FCA and PGA mechanisms.  During that time period, $1.2 billion in fuel and purchased energy costs, including $384 million of MISO charges were recovered from electric customers through the FCA.  In addition, approximately $590 million of purchased natural gas and transportation costs were recovered through the PGA.  In October 2008, the MPUC voted to accept the 2007 gas annual automatic adjustment report.  The 2007 annual electric automatic adjustment report is pending further MPUC action.

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Annual Automatic Adjustment Report for 2008 — In September 2008, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2007 through June 30, 2008.  During that time period, $848.5 million in fuel and purchased energy costs, including $258.8 million of MISO charges, were recovered from Minnesota electric customers through the FCA.  In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the PGA.  The 2008 annual automatic adjustment reports are pending initial comments and MPUC action.

MISO ASM Cost Recovery — On May 9, 2008, NSP-Minnesota and several other Minnesota electric utilities filed jointly for MPUC regulatory approval to recover ASM costs through the Minnesota FCA cost recovery mechanism.  The filing is pending MPUC action after an initial hearing on Dec. 18, 2008.  The MPUC voted to approve FCA recovery of these charges, subject to refund, and required NSP-Minnesota to make a filing that demonstrates that there were benefits of the ASM market after one year of operation.

Gas Meter Module Failures — Approximately 8,700 customers in the St. Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in the Fargo, N.D. area were under billed for a period of time during the 2007-2008 heating season due to the failure of the automated meter reading (AMR) module installed on their natural gas meters.  While the modules failed to register usage, the meters continued to function.  In the May to July 2008 timeframe, NSP-Minnesota rebilled approximately 5,000 of these customers for their estimated consumption during the period the modules registered no consumption and then ceased rebilling as both the MPUC and NDPSC opened investigations into this matter.

On July 2, 2008, NSP-Minnesota received a letter from the NDPSC requesting further information on the module failure.  Subsequent meetings between NSP-Minnesota and NDPSC staff were held in September and October 2008 to discuss NSP-Minnesota’s progress in addressing various NDPSC concerns about NSP-Minnesota’s response.

On Aug. 1, 2008, the MPUC opened a docket and issued a notice directing NSP-Minnesota to file information about the AMR module failure.  NSP-Minnesota responded to the MPUC on Aug. 21, 2008, proposing to rebill affected customers for the unrecorded natural gas usage during the months that no consumption or intermittent usage was recorded.  NSP-Minnesota proposed to employ the process provided by NSP-Minnesota’s natural gas tariff and the MPUC’s rules to estimate usage, which would be consistent with the process used whenever any other type of meter or module failure affecting the measurement of customer consumption occurs.  The MOAG and the OES subsequently submitted comments on NSP-Minnesota’s filing.  The OES comments indicated support for the rebilling plan with certain conditions.  The MOAG raised concerns about the timing of the remediation efforts, and questions whether customers should be responsible for the entire cost of the unbilled natural gas.

On Nov. 6, 2008, the MPUC reviewed the matter and directed NSP-Minnesota to provide additional information prior to making a final decision on the rebilling plan.

On Dec. 3, 2008, NSP-Minnesota made a filing with the NDPSC regarding its commitments and proposed remedies for rebilling affected customers.  The filing outlined the proposed rebilling plan in detail, which committed to a 10-day, go-forward field response to customer inquiries regarding meter accuracy, offered an adjustment to the natural gas true-up to remove the commodity cost for the under recovered gas due to the rebilling process and indicated willingness to work with NDPSC staff on a service quality credit for customers experiencing a module failure.

On Dec. 19, 2008, NSP-Minnesota met with MPUC staff, the OES and MOAG and in January 2009 filed its response to the questions with the MPUC.  NSP-Minnesota indicated a willingness to work with parties to develop a remedy for the current situation, and to develop prospective service quality standards to address this and other concerns around billing accuracy.  NSP-Minnesota has determined that a number of AMR modules designed for commercial customers are defective and as a result is broadening efforts to evaluate the performance of both gas and electric AMR modules.

Annual Review of Remaining Lives — On Oct. 8, 2008, the MPUC approved NSP-Minnesota’s service lives, salvage rates and resulting depreciation rates for its electric and gas production facilities as well as the depreciation study for other gas and electric assets, effective Jan. 1, 2008.  The net impact resulted in a reduction to depreciation expense of $5.6 million recognized in the third quarter, or $7.5 million on an annual basis.

Other

Nuclear Refueling Outage Costs — In November 2007, NSP-Minnesota requested a change in the recovery method for costs associated with refueling outages at its nuclear plants.  The request sought approval to amortize refueling outage costs over the period between refueling outages to better match revenues and expenses.  This request would have reduced 2008

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expenses for the NSP-Minnesota jurisdiction by approximately $25 million due to deferral and amortization over an 18-month period versus expensed as incurred.

On Sept. 16, 2008, the MPUC authorized NSP-Minnesota to use a deferral and amortization method for the nuclear refueling operating and maintenance costs effective Jan. 1, 2008.  The ruling reduced operating and maintenance expenses, but also resulted in revenue deferrals.  The net result is a positive adjustment to year-end earnings of approximately $21 million.

Pending and Recently Concluded Regulatory Proceedings — NDPSC and SDPUC

NSP-Minnesota North Dakota Electric Rate Case — In December 2007, NSP-Minnesota filed a request with the NDPSC to increase North Dakota retail electric rates by $20.5 million, which would be an $18.2 million impact to NSP-Minnesota due to the transfer of certain costs and revenues between base rates and the fuel cost recovery mechanism.  The request was based on an 11.50 percent ROE, an equity ratio of 51.77 percent, and a rate base of approximately $242 million.  Interim rates of $17.2 million became effective in February 2008.

The NDPSC approved a settlement agreement on Dec. 31, 2008, which calls for a base rate increase of $12.8 million, based on an authorized ROE of 10.75 percent.  Key terms of the settlement are listed below:

·Adjustments in depreciation expenses related to service life changes for generation plants and removal rates for transmission and distribution plant, resulting in a $2.5 million decrease in the revenue deficiency.

·Sharing of wholesale margins, refunding to customers 85 percent of asset-based wholesale margins and 50 percent of non-asset-based margins through the fuel clause.  Test year wholesale margins to be shared with customers are estimated to be $1.9 million.

·An electric rate moratorium, under which NSP-Minnesota agreed to not implement an increase in electric rates until Jan. 1, 2011.

·Sharing any earnings in excess of the authorized 10.75 percent ROE, providing customers 50 percent of any earnings above 10.75 percent and 75 percent of any earnings above 11.25 percent.

·The settlement outlines a process for more NDPSC involvement in NSP-Minnesota’s resource planning process.

In addition to approving the settlement, the NDPSC terminated a 2005 filing regarding recovery of MISO Day 2 market charges, thus approving FCA recovery of all MISO Day 2 charges through the FCA retroactively and prospectively.  Based on the final order, there will be an estimated interim rate refund of $6.3 million, which will be refunded back to customers by June 1, 2009.  This refund was accrued for in 2008 and will have no impact on 2009 results.  Final rates will be implemented for service on and after March 1, 2009.

Nuclear Refueling Outage Costs — In late 2007, NSP-Minnesota filed with both the NDPSC and SDPUC a request asking for a change in the recovery method for costs associated with refueling outages at its nuclear plants.  The request is comparable to that filed with the MPUC.  In February 2008, the NDPSC approved the request, indicating that appropriate cost recovery levels would be determined in the pending electric rate case.

The SDPUC approved the NSP-Minnesota’s request to change the accounting method for nuclear refueling outage operating and maintenance cost from a direct expense method to a method that amortizes these costs over the period between outages.

MISO ASM Cost Recovery — On Dec. 24, 2008, NSP-Minnesota filed for NDPSC and SDPUC regulatory approval to recover MISO ASM costs via an FCA cost recovery mechanism.  NSP-Minnesota requested a regulatory order prior to March 1, 2009, when ASM charges and revenues would affect the North Dakota and South Dakota FCA.  On Feb. 11, 2009, the NDPSC concluded that FCA treatment of these costs was already provided for by the rate case settlement. Based on this information, NSP-Minnesota filed to withdraw its request.  The MPUC granted the withdrawal request at its Feb. 25, 2009 open meeting.On Feb. 12, 2009 the SDPUC approved NSP-Minnesota’s request.

NSP-Minnesota South Dakota TCR and ECR Rate Riders — In December 2008, the SDPUC approved two rate riders for recovery of transmission investments and environmental costs effective Feb. 1, 2009.

In February 2007, NSP-Minnesota filed a petition for approval of a tariff establishing a TCR rider for recovery of certain transmission investments.  The TCR rider rate is set to recover approximately $1.9 million during 2009.  In September 2007, NSP-Minnesota filed a petition for approval of a tariff establishing an environmental cost recovery (ECR) rider for recovery of pollution control equipment installed at NSP-Minnesota’s A. S. King plant.  The ECR Rider rate is set to recover approximately $2.5 million during 2009.

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Both rate riders were allowed a return on equity of 9.5 percent according to the terms of their respective settlement agreements.  However, if NSP-Minnesota makes a general rate filing utilizing a 2008 test year, the SDPUC may order that an appropriate ROE value to be utilized under the rider mechanism, subject to true-up for the period from July 1, 2008 to the effective date of the order.

Pending and Recently Concluded Regulatory Proceedings — FERC

MISO Long-Term Transmission Pricing — In October 2005, MISO filed a proposed change to its TEMT to regionalize future cost recovery of certain high voltage transmission projects.  The tariff, called the Regional Expansion Criteria Benefits tariff, would recover certain eligible transmission investments from all transmission service customers in the MISO 15 state region.  In November 2006, the FERC issued an order accepting the regional economic benefits (RECB) I tariff, including a 20 percent limitation on the portion of transmission reliability expansion costs that would be regionalized and recovered from all loads in the MISO region.

Transmission service rates in the MISO region have historically used a rate design in which the transmission cost depends on the location of the load being served, which is referred to as license plate rates.  Costs of existing transmission facilities are thus not regionalized.  In August 2007, MISO and its transmission owners filed a successor rate methodology, to be effective February 2008.American Electric Power (AEP) filed a competing rate proposal that would regionalize certain costs of the existing AEP system over the MISO and PJM RTO regions.  The AEP proposal would shift several million dollars in transmission costs annually to the NSP System.  In January 2008, the FERC rejected the AEP proposal.  On Dec. 18, 2008, the FERC denied AEP’s request for rehearing.

Revenue Sufficiency Guarantee Charges — In April 2006, the FERC issued an order determining that MISO had incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions.  The FERC ordered MISO to resettle all affected transactions retroactive to April 2005.  The RSG charges are collected from MISO customers and paid to generators.  In October 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds, and ordered MISO to submit a compliance filing to implement prospective changes.

In March 2007, the FERC issued orders separately denying rehearing of the FERC order.  Several parties filed appeals to the U.S Court of Appeals for the District of Columbia seeking judicial review of the FERC’s determinations of the allocation of RSG costs among MISO market participants.  Xcel Energy intervened in each of these proceedings.  In August 2007, Ameren Services Company (Ameren) and the Northern Indiana Public Service Company (NIPSCO) filed a joint complaint against MISO at the FERC, challenging the MISO’s FERC-approved methodology for the recovery of RSG costs.  In November 2007, the FERC issued an order instituting a proceeding to review evidence and to establish a RSG cost allocation methodology for market participants under the MISO TEMT.  In March 2008, the MISO filed indicative tariff revisions that reflect an alternative mechanism for allocating RSG charges and costs.  In August 2008, the FERC rejected this filing and issued an order commencing a hearing.

In November 2008, the FERC issued two orders related to RSG.  One order requires the RSG charge allocation to include virtual supply transactions and requires resettlement of RSG charges retroactive to August 2007.  The second order reversed a prior FERC decision and changed the RSG calculation methodology for the May 2006 to August 2007 retroactive period.  Several parties filed requests for rehearing of the November 2008 FERC orders, arguing that the change in RSG allocation should be prospective.  The RSG-related dockets are pending FERC action.

14.Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2008, the estimated cost of the capital expenditure programs and other capital requirements of NSP-Minnesota is approximately $880 million in 2009, $1.3 billion in 2010 and $1.4 billion in 2011.  NSP-Minnesota’s capital forecast includes the following major projects.

Nuclear Capacity Increases and Life Extension — In August 2004, NSP-Minnesota announced plans to pursue 20-year license renewals for the Monticello and Prairie Island nuclear plants.  A renewed operating license was approved and issued for Monticello by the NRC in November 2006 licensing the plant to operate until 2030, and the MPUC order approving the spent fuel storage capacity needed to support plant operations until 2030 went into effect in June 2007.  The application to renew Prairie Island’s operating licenses was submitted to the NRC in April 2008 and the application for a certificate of need

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for additional spent fuel storage capacity to support 20 additional years of plant operation was submitted to the MPUC in May 2008.  Final state and federal approvals are expected in 2010.

NSP-Minnesota is pursuing capacity increases of Monticello and Prairie Island that will total approximately 230 MW, to be implemented, if approved, between 2009 and 2015.  The life extension and capacity increase for Prairie Island Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned during the refueling outage in 2013.  Total capital investment for these activities is estimated to be over $1 billion between 2006 and 2015.  NSP-Minnesota submitted the certificate of need and site permit applications for Monticello’s power uprate in the first quarter of 2008 and the certificate of need and site permit applications for Prairie Island’s power uprate in the second quarter of 2008.  The MPUC approved the Monticello power uprate certificate of need and site permit in December 2008.  Action by the MPUC on the Prairie Island power uprate certificate of need and site permit is expected in fourth quarter of 2009.

Wind Generation — NSP-Minnesota plans to invest approximately $900 million over three years for a 201 MW project in southwestern Minnesota’s Nobles County, called the Nobles Wind Project, and a 150 MW project in Dickey and McIntosh counties in southeastern North Dakota, called the Merricourt Wind Project, expected to be operational by the end of 2010 and 2011, respectively.  NSP-Minnesota is in the process of seeking regulatory approval for the projects, which would be eligible for rider recovery in Minnesota.

CAPX 2020 — In June 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including Xcel Energy, announced that it had identified several groups of transmission projects that proposed to be complete by 2020.  Group 1 project investments are expected to total approximately $1.7 billion, with major construction targeted to begin in 2010 and ending three to five years later.  Xcel Energy’s investment is expected to be approximately $900 million depending on the route and configuration approved by the MPUC.  Approximately 75 percent of the capital expenditures and return on investment for transmission projects are expected to be recovered under an NSP-Minnesota TCR tariff rider mechanism authorized by Minnesota legislation, as well as a similar TCR mechanism passed in South Dakota.  Cost recovery by NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.

MERP Project — In December 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant.  These improvements are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW.  New state-of-the-art emission control equipment was placed in-service for the Allen S. King plant in 2007, and the existing High Bridge facility was replaced with a 575 MW natural gas combined cycle unit, which went into service in May 2008.  The final phase of the MERP program, the new Riverside combined cycle plant, is currently in start-up and scheduled to be in-service by May 2009.  The cumulative investment is approximately $1 billion.  The MPUC has approved a more current recovery of the financing costs related to the MERP.  The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider, which was effective Jan. 1, 2006.

The capital expenditure programs of NSP-Minnesota are subject to continuing review and modification.  Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the desired reserve margin and the availability of purchased power, as well as alternative plans for meeting NSP-Minnesota’s long-term energy needs.  In addition, NSP-Minnesota’s ongoing evaluation of compliance with future requirements to install emission-control equipment and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Fuel Contracts — NSP-Minnesota has contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements.  These contracts expire in various years between 2009 and 2028.  In addition, NSP-Minnesota may be required to pay additional amounts depending on actual quantities shipped under these agreements.  The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass through of most fuel, storage and transportation costs.

The estimated minimum purchases for NSP-Minnesota under these contracts as of Dec. 31, 2008, is as follows:

Coal		Nuclear Fuel		Natural Gas Supply		Gas Storage & Transportation
(Millions of Dollars)
$	665	$	345	$	347	$	993

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Purchased Power Agreements — NSP-Minnesota has entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages and meet operating reserve obligations.  NSP-Minnesota has various pay-for-performance contracts with expiration dates through the year 2032.  In general, these contracts provide for capacity payments, subject to meeting certain contract obligations and energy payments based on actual power taken under the contracts.  Certain contractual payment obligations are adjusted based on indices.  However, the effects of these price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2008, the estimated future payments for capacity, accounted for as executory contracts, that NSP-Minnesota is obligated to purchase, subject to availability, were as follows:

(Millions of Dollars)
2009	$	108.3
2010	111.3
2011	110.7
2012	108.9
2013	111.1
2014 and thereafter	399.5
Total*	$	949.8

* Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Leases — NSP-Minnesota leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases.  Total rental expense under operating lease obligations was approximately $70.7 million, $53.3 million and $35.7 million for 2008, 2007 and 2006, respectively.  Included in total rental expense were purchase power agreement payments of $48.6 million, $29.5 million and $14.5 million in 2008, 2007 and 2006, respectively.

Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with EITF No. 01-8, Determining whether an Arrangement Contains a Lease and SFAS No. 13, Accounting for Leases.  Future commitments under operating leases are:

(Millions of Dollars)	Other Operating Leases		Purchased Power Agreement Operating Leases (a) (b)		Total Operating Leases
2009	$	11.1	$	52.3	$	63.4
2010	8.6		53.1		61.7
2011	6.7		54.0		60.7
2012	5.3		55.0		60.3
2013	5.1		55.9		61.0
Thereafter	9.5		731.0		740.5

(a)Amounts not included in purchase power agreement estimated future payments above.

(b)Purchase power agreement operating leases expire contractually through 2025.

Environmental Contingencies

NSP-Minnesota has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, NSP-Minnesota believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, NSP-Minnesota is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Minnesota, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, NSP-Minnesota would be required to recognize an expense.

Site Remediation — NSP-Minnesota must pay all or a portion of the cost to remediate sites where past activities of NSP-Minnesota or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations including sites of former MGPs operated by NSP-Minnesota, its predecessors or other entities; and third party sites, such as landfills, to which NSP-Minnesota is alleged to be a PRP that sent hazardous materials and wastes.  At Dec. 31, 2008,

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the liability for the cost of remediating these sites was estimated to be $0.4 million, of which $0.2 million was considered to be a current liability.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of NSP-Minnesota’s facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed.  NSP-Minnesota has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations below.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

CAIR — In March 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  The objective of CAIR was to cap emissions of SO2 and NOx in the eastern United States, including Minnesota.  In July 2008, the U. S. Court of Appeals for the District of Columbia vacated CAIR and remanded the rule to the EPA.  On Dec. 23, 2008, the court reinstated CAIR while the EPA develops new regulations in accordance with the court’s July opinion.

As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap-and-trade program.  State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

The EPA has drafted a proposed rule to stay the effectiveness of CAIR in Minnesota.  As such, cost estimates are not included at this time for NSP-Minnesota.

CAMR — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury rules and legislation.  Costs to comply with the Minnesota Mercury Emissions Reduction Act of 2006 are discussed below.

Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants.  For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities.  Under the Act, NSP-Minnesota is operating and maintaining continuous mercury emission monitoring systems.  The information obtained will be used to establish a baseline from which to measure mercury emission reductions.

On Dec. 21, 2007, NSP-Minnesota filed mercury emission reduction plans for two dry scrubbed units, Sherco Unit 3 and A. S. King, as well as a comprehensive emissions reduction and capacity upgrade proposal for Sherco Units 1 and 2 (wet scrubbed units).  A revised specific mercury reduction proposals for these units will be filed by Dec. 31, 2009, as required by the legislation.  Current plans are to install a sorbent injection system at both A. S. King and Sherco Unit 3.  Implementation would occur by Dec. 31, 2009, at Sherco Unit 3 and by Dec. 31, 2010, for A. S. King.  For these units, the current total capital costs estimate is $8.5 million, with the annual cost estimate of $4.3 million for A. S. King and $4.2 million for Sherco Unit 3.  For Sherco Units 1 and 2, the current cost estimate is $13.6 million for capital and $10 million annual expenses.

Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004.  Cost recovery provisions of the Act also apply to these other environmental initiatives.  In September 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act.  In January 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million.  On Aug. 26, 2008, NSP-Minnesota filed a request with the MPUC to increase the deferral to $19.4 million as NSP-Minnesota anticipated exceeding the authorized deferral amount in September 2008.  On Nov. 6, 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.

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Voluntary Capacity Upgrade and Emissions Reduction Filing — In December 2007, NSP-Minnesota filed a plan with the MPCA and MPUC for reducing mercury emissions by up to 90 percent at the Sherco Unit 3 and A. S. King plants.  Currently, the estimated project costs are approximately $8.5 million.  At the same time, NSP-Minnesota submitted a revised filing to the MPUC for a major emissions reduction project at Sherco Units 1 and 2 to reduce emissions and expand capacity.  The revised filing has estimated project costs of approximately $1.1 billion.  The filing also contains alternatives for the MPUC to consider to add additional capacity and to achieve even lower emissions.  If selected, these alternatives could range from $90.8 to $330.8 million in addition to the $1.1 billion proposal.  NSP-Minnesota’s investments are subject to MPUC approval of a cost recovery mechanism.  The MPCA has issued its assessment that the Sherco Unit 3 and A. S. King plans are appropriate.  In light of recent significant changes in the national economy, lower forecast of energy consumption, and new information concerning an emerging technology that may be more cost effective, NSP-Minnesota filed a request with the MPUC to withdraw the plan on Nov. 6, 2008, to allow NSP-Minnesota to reevaluate alternatives.  The MPUC granted the withdrawal request on Dec. 9, 2008.

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.

The EPA required states to develop implementation plans to comply with BART by December 2007.  NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  In July 2008, the U. S. Circuit Court of Appeals for the District of Columbia vacated CAIR and remanded the rule to the EPA.  In December 2008, the Court of Appeals reinstated CAIR while the EPA develops new regulations in accordance with the Court’s July opinion.  For Minnesota facilities, however, the EPA has drafted a proposed rule that would stay the effectiveness of CAIR within the state.  Therefore, the MPCA has reestablished the BART process and requested that companies with BART-eligible units inform the MPCA whether the company will rely on the initial 2006 BART determination submittal or if they intend to submit a revised analysis.  On Nov. 13, 2008, NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCA to account for increased construction and equipment costs.  The underlying conclusions and proposed emission control equipment, however, remained unchanged from the original 2006 BART analysis.

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants.  Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit challenging the phase II rulemaking.  In January 2007, the court issued its decision and remanded virtually every aspect of the rule to the EPA for reconsideration.  In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the court-ordered remand.  As a result, the rule’s compliance requirements and associated deadlines are currently unknown.  It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.  In April 2008, the U.S. Supreme Court granted limited review of the Second Circuit’s opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA.  A decision is not expected until 2009.

The MPCA exercised its authority under “best professional judgment” to require Black Dog Generating Station in its recently renewed wastewater discharge permit to create a plan by April 2010 to reduce the plant intake’s impact on aquatic wildlife.  NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.

Asset Retirement Obligations

NSP-Minnesota records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with FASB Statement No. 143, Accounting for Asset Retirement Obligations, (SFAS No. 143).  This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71.

Recorded ARO — AROs have been recorded for plant related to nuclear production, steam production, electric transmission and distribution, gas distribution and office buildings.  The steam production obligation includes asbestos, ash containment facilities, radiation sources and decommissioning.  The asbestos recognition associated with the steam production includes certain plants at NSP-Minnesota.  NSP-Minnesota also recorded asbestos recognition for its general office building. 

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Generally, this asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  AROs also have been recorded for NSP-Minnesota steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.  The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities.  A new ARO has been recorded for steam production plant related to radiation sources in equipment used to monitor the flow of coal, lime and other materials through feeders.  The origination date on the new ARO is 2008, the in-service date of the monitoring equipment.

In 2008, NSP-Minnesota recognized an ARO associated with the wind turbines at the new Grand Meadow Wind Farm.  The turbines are located on leased property, and under the lease agreements, must be removed when no longer used.  The recognition of the ARO was due to the units being placed in service in the fourth quarter of 2008.

NSP-Minnesota recognized an ARO for the retirement costs of natural gas mains and for the removal of electric transmission and distribution equipment.  The electric transmission and distribution ARO consists of many small potential obligations associated with polychlorinated biphenyls (PCBs), mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps.  These electric and natural gas assets have many in-service dates for which it is difficult to assign the obligation to a particular year.  Therefore, the obligation was measured using an average service life.

For the nuclear assets, the ARO associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello and Prairie Island, originates with the in-service date of the facility.  Monticello began operation in 1971.  Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively.  See Note 15 to the consolidated financial statements for further discussion of nuclear obligations.

A reconciliation of the beginning and ending aggregate carrying amounts of NSP-Minnesota’s AROs is shown in the table below for the 12 months ended Dec. 31, 2008 and Dec. 31, 2007, respectively:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2008		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2008
Electric Utility Plant:
Steam production asbestos	$	22,423	$	—	$	—	$	1,279	$	(4,182	)	$	19,520
Steam production ash containment	18,111		—		—		1,001		(5,268		)	13,844
Steam production radiation sources	—		61		—		—		—			61
Nuclear production decommissioning	1,209,746		—		—		71,370		(267,774		)	1,013,342
Wind production	—		7,408		—		39		—			7,447
Electric transmission and distribution	125		—		—		7		19			151
Gas Utility Plant:
Gas transmission and distribution	12,685		—		—		314		(12,754		)	245
Common Utility and Other Property:
Common general plant asbestos	1,278		—		—		70		(269		)	1,079
Total liability	$	1,264,368	$	7,469	$	—	$	74,080	$	(290,228	)	$	1,055,689

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear AROs is $1.1 billion as of Dec. 31, 2008, including external nuclear decommissioning investment funds and internally funded amounts.

A new decommissioning study filed with the MPUC in 2008 proposed the extension of the final removal date of the Monticello and Prairie Island nuclear plants by 14 and 26 years, respectively, effective Jan. 1, 2009.  As a result of the studies for the Monticello and Prairie Island nuclear plants, the nuclear production decommissioning ARO and related regulatory asset decreased by $128.5 million and $139.3 million, respectively, in the fourth quarter of 2008.

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NSP-Minnesota also incurred revisions to prior estimates for asbestos, ash ponds, gas distribution and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2007		Liabilities Recognized		Liabilities Settled		Accretion		Revisions To Prior Estimates			Ending Balance Dec. 31, 2007
Electric Utility Plant:
Steam production asbestos	$	22,169	$	—	$	—	$	1,262	$	(1,008	)	$	22,423
Steam production ash containment	17,163		—		—		948		—			18,111
Nuclear production decommissioning	1,256,763		—		—		73,914		(120,931		)	1,209,746
Electric transmission and distribution	940		—		—		20		(835		)	125
Gas Utility Plant:
Gas transmission and distribution	12,378		—		—		307		—			12,685
Common Utility and Other Property:
Common general plant asbestos	1,858		—		—		100		(680		)	1,278
Total liability	$	1,311,271	$	—	$	—	$	76,551	$	(123,454	)	$	1,264,368

On Sept. 21, 2007, the MPUC approved NSP-Minnesota’s remaining lives depreciation filing lengthening the life of the Monticello nuclear plant by 20 years, effective Jan. 1, 2007, which decreased the related ARO and related regulatory asset by $120.9 million in the third quarter of 2007.

Removal Costs — NSP-Minnesota accrues an obligation for plant removal costs for generation, transmission and distribution facilities.  Generally, the accrual of future non-ARO removal obligations is not required.  However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.  These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities.  Given the long periods over which the amounts were accrued and the changing of rates through time, NSP-Minnesota has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.  Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities under SFAS No. 71.  Removal costs as of Dec. 31, 2008 and 2007 were $354 million and $342 million, respectively.

Nuclear Insurance

NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $12.5 billion under the Price-Anderson amendment to the Atomic Energy Act of 1954, as amended.  NSP-Minnesota has secured $300 million of coverage for its public liability exposure with a pool of insurance companies.  The remaining $12.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident.  NSP-Minnesota is subject to assessments of up to $117.5 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States.  The maximum funding requirement is $17.5 million per reactor during any one year.  These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes.  The NRC’s last adjustment was effective Oct. 29, 2008.  The next adjustment is due on or before Oct. 29, 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL).  The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites.  NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units.  Premiums are expensed over the policy term.  All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated reserve funds.  Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance

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coverage.  However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $16.1 million for business interruption insurance and $29.7 million for property damage insurance if losses exceed accumulated reserve funds.

Legal Contingencies

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material adverse effect on NSP-Minnesota’s financial position and results of operations.

Environmental Litigation

Carbon Dioxide Emissions Lawsuit — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit.  On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit.  In June 2007 the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal.  Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by the EPA under the CAA.  In July 2007, in response to the request of the Court of Appeals,  the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal.  The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit.  Oral arguments were presented to the Court of Appeals on Aug. 6, 2008.  Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008.  No explanation was given for the order.  The Court of Appeals has taken the matter under advisement.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy, the parent company of NSP-Minnesota, and 23 utilities, oil, gas and coal companies.  The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that Defendants’ emission of CO2 and other greenhouse gases (GHG) contribute to global warming, which is harming their village.  Plaintiffs claim that as a consequence, the entire village must be relocated at a cost of between $95 million and $400 million.  Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other.  Xcel Energy was not named in the civil conspiracy claim.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008.  The matter has now been fully briefed, with oral arguments set for May 19, 2009.  It is unknown when the court will render a decision.

Employment, Tort and Commercial Litigation

Siewert vs. Xcel Energy — In June 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production, injury and damage to a dairy herd as a result of

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stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  After its motion to dismiss plaintiffs’ claims was denied, NSP-Minnesota filed a motion to certify questions for immediate appellate review.  In October 2007, the court granted NSP- Minnesota’s motion for certification, and oral arguments took place on Sept. 11, 2008.  Mediation took place on Oct. 14, 2008, but the matter was not resolved.  In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial.  The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review on Feb. 17, 2009.

Hoffman vs. Northern States Power Company — In March 2006, a purported class action complaint was filed in Minnesota state court, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box.  Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC.  Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years.  In August 2006, NSP-Minnesota filed a motion for dismissal on the pleadings.  In November 2006, the court issued an order denying NSP-Minnesota’s motion, but later, pursuant to a motion by NSP-Minnesota, certified the issues raised in NSP-Minnesota’s original motion for appeal as important and doubtful, and NSP-Minnesota filed an appeal with the Minnesota Court of Appeals.  In January 2008, the Minnesota Court of Appeals determined the plaintiffs’ claims are barred by the filed rate doctrine and remanded the case to the district court for dismissal.  Plaintiffs petitioned the Minnesota Supreme Court for discretionary review, and the Supreme Court granted the petition.  Oral argument took place on Nov. 4, 2008.  It is unknown when a decision will be issued.

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota.  At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004.  On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In December 2007, the court denied the DOE’s motion for reconsideration.  In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue.  In April 2008, the DOE asked the Court of Appeals to stay briefing until the appeals in several other nuclear waste cases have been decided, and the Court of Appeals granted the request.  In December 2008, NSP-Minnesota made a motion in the Court of Appeals to lift the stay, which was denied by the Court of Appeals in February 2009.  Results of the judgment will not be recorded in earnings until the appeal and regulatory treatment and amounts to be shared with ratepayers have been resolved.  Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U.S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract.  This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel.  The amount of such damages is expected to exceed $40 million.  In January 2008, the court granted the DOE’s motion to stay, but the stay was lifted in November 2008.  The court’s scheduling order provides that the parties will exchange expert reports in 2009, and that all discovery will be completed by the end of 2009.  Trial is expected to take place in 2010.

Fargo Gas Explosion — In September 2008, an explosion occurred at a duplex in Fargo, N.D.  The explosion destroyed one side of the duplex and resulted in injuries to some of the residents.  Xcel Energy subsequently provided a report to the U.S. Dept. of Transportation Pipeline and Hazardous Materials Safety Administration stating that natural gas migrated into the house and was ignited by an unknown source.  Investigators identified a natural gas leak the size of a pinhole located 18 inches underground.  The property owners and attorneys representing the injured residents have put Xcel Energy on notice of potential claims.  Investigation into the incident is continuing.

15. Nuclear Obligations

Fuel Disposal — NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants.  The DOE is responsible for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants.  NSP-Minnesota has funded its portion of the DOE’s permanent disposal program since 1981.  The fuel disposal fees are based on a charge of 0.1 cent per Kwh sold to customers from nuclear generation.  Fuel expense includes the DOE fuel disposal assessments of approximately $13 million in 2008, 2007 and 2006, respectively.  In total, NSP-Minnesota

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had paid approximately $386 million to the DOE through Dec. 31, 2008.  The Nuclear Waste Policy Act of 1982 required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998.  In 1996, the DOE notified commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent storage or disposal facility will not be available until at least 2010.  NSP-Minnesota and other utilities have commenced lawsuits against the DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist of storage pools and dry cask facilities at both sites.  The amount of spent fuel storage capacity currently authorized by the NRC and the MPUC will allow NSP-Minnesota to continue operation of its Prairie Island nuclear plant until the end of its current license terms in 2013 and 2014 and its Monticello nuclear plant until the end of its renewed operating license in 2030.  Other alternatives for spent fuel storage are being investigated until a DOE facility is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of electric utilities.

Regulatory Plant Decommissioning Recovery — Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is planned for the period from cessation of operations through 2067, assuming the prompt dismantlement method.  NSP-Minnesota is currently recording the regulatory costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in a regulatory liability account.  The total decommissioning cost obligation is recorded as an ARO in accordance with SFAS No. 143.

Monticello began operation in 1971 and with its renewed operating license and certificate of need for spent fuel capacity to support 20 years of extended operation can operate until 2030.  Prairie Island units 1 and 2 began operation in 1973 and 1974, respectively, and are currently licensed to operate until 2013 and 2014, respectively.  The Monticello 20-year depreciation life extension until September 2030 was granted by the MPUC on Sept. 21, 2007.  Construction of the Monticello dry-cask storage facility commenced on June 4, 2007.  Construction of the facility is complete and 10 of the 30 canisters authorized have been filled and placed in the facility.  Plant assessments and other work for the Prairie Island license renewal applications started in 2006.  In April 2008, NSP-Minnesota filed an application with the NRC to renew the operating license of its two nuclear reactors at Prairie Island for an additional 20 years until 2033 and 2034, respectively.  The PIIC filed contentions in the NRC’s license renewal proceeding in August 2008.  The PIIC request was referred to an ASLB for review.  The ASLB has granted the PIIC hearing request and has admitted seven of the 11 contentions filed.  The resulting adjudicatory process and hearings are expected to add approximately eight months onto the NRC’s standard 22 month review schedule (without hearings) resulting in the NRC not making a decision on whether or not to renew the Prairie Island operating licenses until late 2010.  An application for a certificate of need to expand the spent fuel storage capacity at Prairie Island to support 20 additional years of operation was filed with the MPUC in May 2008.  It is expected that the MPUC will act in late 2009 allowing the MPUC decision to be stayed during the 2010 session of the Minnesota legislature before going into effect.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC, when decommissioning commences.  The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in March 2006, using 2005 cost data with the next study update submitted in October 2008 for the 2009 accrual.  The MPUC approval, decreasing 2006 decommissioning funding for Minnesota retail customers, resulted from an extension of remaining life for the Monticello unit by 10 years (from 2010 to 2020).  Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins.  The assets held in trusts, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government securities that mature in one to 20 years and common stock of public companies.  NSP-Minnesota plans to reinvest matured securities until decommissioning begins.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific cost studies and a presumed level of dedicated funding.  Cost studies quantify decommissioning costs in current dollars.  Current authorized funding presumes that costs will escalate in the future at a rate of 3.61 percent per year.  The total estimated decommissioning costs that will ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved plant-recovery period.  This annuity approach uses an assumed rate of return on funding, which is currently 5.40 percent, net of tax, for external funding.  The net unrealized gain on nuclear decommissioning investments is deferred as a regulatory liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

At Dec. 31, 2008, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning expense of $1.3 billion.  The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved

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regulatory recovery parameters.  Xcel Energy believes future decommissioning cost expense will continue to be recovered in customer rates.  These amounts are not those recorded in the financial statements for the ARO in accordance with SFAS No. 143.

(Thousands of Dollars)	2008			2007
Estimated decommissioning cost obligation from most recently approved study (2005 dollars)	$	1,683,750		$	1,683,750
Effect of escalating costs to 2008 and 2007 dollars (3.61 percent per year)	189,012			123,761
Estimated decommissioning cost obligation in current dollars	1,872,762			1,807,511
Effect of escalating costs to payment date (3.61 percent per year)	1,254,064			1,319,315
Estimated future decommissioning costs (undiscounted)	3,126,826			3,126,826
Effect of discounting obligation (using risk-free interest rate)	(1,847,526		)	(1,502,030		)
Discounted decommissioning cost obligation	1,279,300			1,624,796
Assets held in external decommissioning trust	1,075,294			1,317,564
Discounted decommissioning obligation in excess of assets currently held in external trust	$	204,006		$	307,232

Decommissioning expenses recognized include the following components:

(Thousands of Dollars)	2008			2007			2006
Annual decommissioning cost expense reported as depreciation expense:
Externally funded	$	43,239		$	43,392		$	48,069
Internally funded (including interest costs)	(819		)	(759		)	(5,046		)
Net decommissioning expense recorded	$	42,420		$	42,633		$	43,023

Reductions to expense for internally-funded portions in 2008, 2007 and 2006 are a direct result of the 2005 decommissioning study jurisdictional allocation and 100 percent external funding approval, effectively unwinding the remaining internal fund over the remaining operating life of the unit.  The 2005 nuclear decommissioning filing approved in 2006 has been used for the regulatory presentation.  The change in estimated decommission obligations was calculated using a cost estimate for Monticello assuming a 60-year operating life.

16. Regulatory Assets and Liabilities

NSP-Minnesota’s consolidated financial statements are prepared in accordance with the provisions of SFAS No. 71, as discussed in Note 1 to the consolidated financial statements.  Under SFAS No. 71, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot use SFAS No. 71 accounting.  If changes in the utility industry or the business of NSP-Minnesota no longer allow for the application of SFAS No. 71 under GAAP, NSP-Minnesota would be required to recognize the write-off of regulatory assets and liabilities in its consolidated statement of income.

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The components of unamortized regulatory assets and liabilities on the consolidated balance sheets of NSP-Minnesota are:

		Remaining Amortization
(Thousands of Dollars)	See Note	Period	2008		2007
Regulatory Assets
Current regulatory asset — Unrecovered fuel costs	1	Less than one year	$	26,605	$	36,857
Net AROs (a)	14	Plant lives	$	256,791	$	20,776
Pension and employee benefit obligations		Various	153,892		—
AFDC recorded in plant (b)		Plant lives	124,242		112,750
Contract valuation adjustments (c)	10	Term of contract	86,937		82,137
Renewable resource costs		Two to three years	44,790		44,238
Nuclear outage costs	13	Generally 18-24 months	40,690		—
Losses on reacquired debt	1	Term of related debt	26,081		28,666
Conservation programs (b)		Various	23,911		18,293
Unrecovered natural gas costs	1	One to two years	14,657		22,505
Purchased power contracts costs	10	Term of contract	13,228		—
Nuclear fuel storage		Four years	9,652		11,578
MISO day 2 costs		To be determined in future rate proceedings	8,742		5,826
State commission accounting adjustments (b)		Plant lives	4,398		4,158
Other		Various	20,701		8,855
Total noncurrent regulatory assets			$	828,712	$	359,782
Regulatory Liabilities
Plant removal costs	14		$	354,117	$	342,207
Deferred income tax adjustments			30,787		42,611
Investment tax credit deferrals			27,797		30,211
Contract valuation adjustments (c)			23,355		14,275
Nuclear outage costs collected in advance from customers			13,678		—
Gain on sale of emission allowances			2,727		2,885
Interest on income tax refunds			1,736		3,472
Pension and employee benefit obligations	8		—		195,394
Other			5,683		8,173
Total noncurrent regulatory liabilities			$	459,880	$	639,228

(a)Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

(b)Earns a return on investment in the ratemaking process.  These amounts are amortized consistent with recovery in rates.

(c)Includes the fair value of certain long-term purchased power agreements used to meet energy capacity requirements.

17. Segments and Related Information

NSP-Minnesota has two reportable segments, regulated electric utility and regulated natural gas utility.

·NSP-Minnesota’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, North Dakota and South Dakota.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes NSP-Minnesota’s commodity trading operations.

·NSP-Minnesota’s regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.

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Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include appliance repair services, nonutility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.

Operating results from the regulated electric utility and regulated natural gas utility serve as the primary basis for the chief operating decision maker to evaluate the dual performance of NSP-Minnesota.

To report net income for regulated electric and regulated natural gas utility segments, NSP-Minnesota must assign or allocate all costs and certain other income.  In general, costs are:

·Directly assigned wherever applicable;

·Allocated based on cost causation allocators wherever applicable; or

·Allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the consolidated financial statements.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

(Thousands of Dollars)	Regulated Electric		Regulated Natural Gas		All Other			Reconciling Eliminations			Consolidated Total
2008
Operating revenues from external customers	$	3,584,109	$	889,958	$	19,569		$	—		$	4,493,636
Intersegment revenues	564		4,863		—			(5,427		)	—
Total revenues	$	3,584,673	$	894,821	$	19,569		$	(5,427	)	$	4,493,636
Depreciation and amortization	$	376,768	$	35,209	$	385		$	—		$	412,362
Interest charges and financing costs	162,697		17,464		1,454			(386		)	181,229
Income tax expense	167,961		12,509		(2,234		)	—			178,236
Net income	$	250,785	$	28,887	$	5,469		$	—		$	285,141
2007
Operating revenues from external customers	$	3,476,674	$	776,971	$	18,569		$	—		$	4,272,214
Intersegment revenues	655		16,261		—			(16,916		)	—
Total revenues	$	3,477,329	$	793,232	$	18,569		$	(16,916	)	$	4,272,214
Depreciation and amortization	$	372,270	$	32,896	$	403		$	—		$	405,569
Interest charges and financing costs	151,012		17,256		707			(16		)	168,959
Income tax expense	165,531		11,315		5,179			—			182,025
Net income (loss)	$	246,086	$	21,485	$	(269	)	$	—		$	267,302
2006
Operating revenues from external customers	$	3,265,371	$	744,635	$	17,609		$	—		$	4,027,615
Intersegment revenues	496		8,929		—			(9,425		)	—
Total revenues	$	3,265,867	$	753,564	$	17,609		$	(9,425	)	$	4,027,615
Depreciation and amortization	$	393,560	$	31,566	$	385		$	—		$	425,511
Interest charges and financing costs	134,347		15,539		1,040			(4		)	150,922
Income tax expense (benefit)	138,077		5,448		(15,919		)	—			127,606
Net income	$	242,815	$	9,674	$	19,821		$	—		$	272,310

18.  Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including NSP-Minnesota.  The services are provided and billed to each subsidiary in accordance with Service Agreements executed by each subsidiary.  Costs are charged directly to the subsidiary which uses the service whenever possible and are allocated if they cannot be directly assigned.

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Xcel Energy has established a utility money pool arrangement with the utility subsidiaries.  See Note 4 for further discussion of this borrowing arrangement.

Nuclear Plant Operation — On Sept. 28, 2007, NSP-Minnesota obtained 100 percent ownership in NMC as a result of Wisconsin Energy Corporation (WEC), exiting the partnership due to the sale of its Point Beach Nuclear Plant to FPL Energy.  Accordingly, the results of operations of NMC and the estimated fair value of assets and liabilities were included in NSP-Minnesota’s consolidated financial statements from the Sept. 28, 2007, transaction date.  WEC was required to pay an exit fee and surrender all of its equity interest in NMC upon exiting.  The effect of this transaction was not material to the financial position or the results of operations to NSP-Minnesota for the year ended Dec. 31, 2007.  NSP-Minnesota has reintegrated its nuclear operations into its generation operations.  The NRC transferred the nuclear operating licenses from NMC to NSP-Minnesota effective Sept. 22, 2008.

Prior to Sept. 28, 2007, NSP-Minnesota also paid its proportionate share of the operating expenses and capital improvement costs incurred by NMC, in accordance with the Nuclear Power Plant Operating Services Agreement.  NSP-Minnesota paid the NMC $235.2 million in 2007 and $292.5 million in 2006.

The electric production and transmission costs of the entire NSP system are shared by NSP-Minnesota and NSP-Wisconsin.  The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:

(Thousands of Dollars)	2008		2007		2006
Operating revenues:
Electric utility	$	390,143	$	372,215	$	322,733
Natural gas utility	312		366		350
Operating expenses:
Purchased power	64,195		79,345		61,342
Transmission expense	42,167		40,872		38,061
Other operations — paid to Xcel Energy Services Inc.	275,618		267,281		284,108
Interest expense	1,645		1,742		1,083
Interest income	2,536		1,422		4,497

Accounts receivable and payable with affiliates at Dec. 31, was:

	2008				2007
(Thousands of Dollars)	Accounts Receivable		Accounts Payable		Accounts Receivable		Accounts Payable
NSP-Wisconsin	$	12,416	$	—	$	20,918	$	—
PSCo	—		15,987		—		17,440
SPS	—		3,330		—		8,332
Other subsidiaries of Xcel Energy	2		32,974		10,160		28,203
	$	12,418	$	52,291	$	31,078	$	53,975

NSP-Wisconsin obtains short-term borrowings from NSP-Minnesota at NSP-Minnesota’s average daily interest rate, including the cost of NSP-Minnesota’s compensating balance requirements.  At Dec. 31, 2008 and 2007, NSP-Minnesota had notes receivable outstanding from NSP-Wisconsin in the amount of $0.0 million and $58.6 million, respectively.

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19. Summarized Quarterly Financial Data (Unaudited)

Due to the seasonality of NSP-Minnesota’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.  Summarized quarterly unaudited financial data is as follows:

	Quarter Ended
(Thousands of Dollars)	March 31, 2008		June 30, 2008		Sept. 30, 2008		Dec. 31, 2008
Operating revenues	$	1,267,724	$	1,021,865	$	1,103,096	$	1,100,951
Operating income	130,865		112,003		218,319		146,014
Net income	63,968		48,353		110,340		62,480

	Quarter Ended
(Thousands of Dollars)	March 31, 2007		June 30, 2007		Sept. 30, 2007		Dec. 31, 2007
Operating revenues	$	1,145,635	$	976,725	$	1,089,170	$	1,060,684
Operating income	97,858		122,804		244,430		125,263
Net income	42,503		56,374		121,456		46,969

Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

During 2007 and 2008, and through the date of this report, there were no disagreements with the independent public accountants for NSP-Minnesota on accounting principles or practices, financial statement disclosures or auditing scope or procedures.

Item 9A(T) — Controls and Procedures

Disclosure Controls and Procedures

NSP-Minnesota maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of Dec. 31, 2008, based on an evaluation carried out under the supervision and with the participation of NSP-Minnesota’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that NSP-Minnesota’s disclosure controls and procedures were effective.

Internal Controls Over Financial Reporting

No change in NSP-Minnesota’s internal control over financial reporting has occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, NSP-Minnesota’s internal control over financial reporting.  NSP-Minnesota maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting.  NSP-Minnesota has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level.  During the year and in preparation for issuing its report for the year ended Dec. 31, 2008 on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, NSP-Minnesota conducted testing and monitoring of its internal control over financial reporting.  Based on the control evaluation, testing and remediation performed, NSP-Minnesota did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

This annual report does not include an attestation report of NSP-Minnesota’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by NSP-Minnesota’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit NSP-Minnesota to provide only management’s report in this annual report.

Item 9B — Other Information

None.

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PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for NSP-Minnesota in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships, Related Transactions and Director Independence

Item 14 — Principal Accounting Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2009 Annual Meeting of Shareholders, which is incorporated by reference.

PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.Consolidated Financial Statements:

Management Report on Internal Controls — For the year ended Dec. 31, 2008.

Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2008, 2007 and 2006.

Consolidated Statements of Income — For the three years ended Dec. 31, 2008, 2007 and 2006.

Consolidated Statements of Cash Flows — For the three years ended Dec. 31, 2008, 2007 and 2006.

Consolidated Balance Sheets — As of Dec. 31, 2008 and 2007.

2.Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2008, 2007 and 2006.

3.Exhibits

*Indicates incorporation by reference

+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01*	Articles of Incorporation and Amendments of Northern Power Corp. (renamed Northern States Power Co. (a Minnesota corporation) on Aug. 21, 2000)(Exhibit 3.01 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.02*	By-Laws of Northern States Power Co. (a Minnesota corporation) (Exhibit 3.02 to Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
3.03*	By-Laws of Northern States Power Co. as Amended and Restated (a Minnesota corporation) (Exhibit 3.02 to Form 8-K (file no. 001-31387) dated June 3, 2008).
4.01*	Supplemental and Restated Trust Indenture, dated May 1, 1988, from Northern States Power Co. (a Minnesota corporation) to Harris Trust and Savings Bank, as Trustee. (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year 1988, file no. 001-03034). Supplemental Indentures between NSP-Minnesota and said Trustee, , dated as follows:
4.02*	Oct. 1, 1992 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Oct. 13, 1992).
4.03*	April 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 1993).
4.04*	Dec. 1, 1993 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 7, 1993).
4.05*	June 1, 1995 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
4.06*	March 1, 1998 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
4.07*	May 1, 1999 (Exhibit 4.49 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.08*	June 1, 2000 (Exhibit 4.50 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.09*	Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.10*	Trust Indenture, dated July 1, 1999, between Northern States Power Co. (a Minnesota corporation) and

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	Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.11*	Supplemental Trust Indenture, dated July 15, 1999, between Northern States Power Co. (a Minnesota corporation) and Norwest Bank Minnesota, National Association, as Trustee. (Exhibit 4.02 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
4.12*	Supplemental Trust Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, Northern States Power Co. (a Minnesota corporation) and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
4.13*	Supplemental Trust Indenture dated June 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.05 to Form 10-Q (file no. 000-31387) dated Sept. 30, 2002).
4.14*	Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.06 to Form 10-Q (file no. 000-31387) dated Sept. 30, 2002).
4.15*	Supplemental Trust Indenture dated July 1, 2002, supplemental to the Indenture dated July 1, 1999, between Northern States Power Co. (a Minnesota Corporation) and Wells Fargo Bank Minnesota, National Association, as trustee (Exhibit 4.01 to Form 8-K (file no. 000-31709) dated July 8, 2002).
4.16*	Supplemental Trust Indenture dated Aug. 1, 2002, supplemental to the Indentures dated Feb. 1, 1937 and May 1, 1988, between Northern States Power Co. (a Minnesota Corporation) and BNY Midwest Trust Co., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 22, 2002).
4.17*	Supplemental Trust Indenture dated Aug. 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988 (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated Aug. 6, 2003).
4.18*	Supplemental Trust Indenture dated May 1, 2003 between Northern States Power Co. (a Minnesota corporation) and BNY Midwest Trust Co., supplementing indentures dated Feb. 1, 1937 and May 1, 1988. (Exhibit 4.73 to Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2003).
4.19*	Supplemental Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250,000,000 principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated July 14, 2005).
4.20*	Supplemental Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400,000,000 principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated May 18, 2006).
4.21*	$500,000,000 Credit Agreement dated Dec. 14, 2006 between NSP-Minnesota and various lenders (Exhibit 99.01 to Form 8-K of Xcel Energy (file no. 001-3034) dated Dec. 14, 2006).
4.22*	Supplemental Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
4.23*	Supplemental Indenture dated March 1, 2008 between Northern States Power Company and The Bank of New York Trust Company, N.A., as successor trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008.
10.01*+	Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+	Xcel Energy Inc. Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+	Amended and Restated Executive Long-Term Incentive Award Stock Plan. (Exhibit 10.02 to NSP-Minnesota Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+	New Century Energies Omnibus Incentive Plan, (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+	Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+	Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+	Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+	Xcel Energy Non-employee Directors’ Deferred Compensation Plan (Exhibit 10.24 to Xcel Energy Form 10-K (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+	Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to

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	Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+	Employment Agreement, effective Dec. 15, 1997, between company and Mr. Paul J. Bonavia, as amended (Exhibit 10.25 to Xcel Energy Form 10-K (file no. 001-03034) for the year ended Dec. 31, 2004).
10.11*+	Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.06 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.13*+	Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.14*+	Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.15*+	Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).
10.16*+	Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement dated April 11, 2005).
10.17*+	Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.18*+	Agreement dated March 20, 2007 between Mr. Gary R. Johnson and Xcel Energy Inc. (Exhibit 10.1 to Form 8-K (file no. 001-03034) dated March 20, 2007).
10.19*+	Letter dated Sept. 19, 2007, from Xcel Energy Inc. to the U.S. Department of Justice (DOJ) submitting its offer to settle the COLI tax dispute and Letter dated Sept. 21, 2007 from the DOJ to Xcel Energy Inc. accepting the settlement offer. (Exhibit 10.1 to Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2007).
10.20*+	Amendment Four to Employment Agreement between Xcel Energy Inc. and Paul Bonavia (Exhibit 10.02 to Xcel Energy’s Form 8-K (file no. 001-03034) dated May 23, 2007).
10.21*+	First Amendment to the Xcel Energy Inc. Executive Annual Incentive Award Plan effective as of Jan. 1, 2009 (Exhibit 10.21 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.22*+	First Amendment to the Xcel Energy Inc. Omnibus Incentive Award Plan as of Jan. 1, 2009 (Exhibit 10.22 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.23*	Facilities Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06I to file no. 2-54310).
10.24*	Transactions Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06J to file no. 2-54310).
10.25*	Coordinating Agreement, dated July 21, 1976, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board relating to the interconnection of the 500 KV line. (Exhibit 5.06K to file no. 2-54310).
10.26*	Ownership and Operating Agreement, dated March 11, 1982, between Northern States Power Co. (a Minnesota corporation), Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3. (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.27*	Power Agreement, dated June 14, 1984, between Northern States Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board, extending the agreement scheduled to terminate on April 30, 1993, to April 30, 2005. (Exhibit 10.03 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
10.28*	Power Agreement, dated August 1988, between Northern States Power Co. (a Minnesota corporation) and Minnkota Power Co. (Exhibit 10.08 to Form 10-K for the year 1988, file no. 001-03034).
10.29*	Amended agreement for the sale of thermal energy dated Jan. 1, 1983 between NRG Energy (formerly known as Norenco Corp.) and Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.33 to NRG’s Registration on Form S-1, file no. 333-35096).
10.30*	Operations and maintenance agreement dated Nov. 1, 1996 between NRG Energy and Northern States Power Co. (a Minnesota corporation). (Exhibit 10.34 to NRG’s Registration on Form S-1, file no. 333-35096).
10.31*	Amended Agreement for the sale of thermal energy and wood byproduct dated Dec. 1, 1986 between Northern States Power Co. (a Minnesota corporation) and Norenco Corp. (Exhibit 10.36 to NRG’s Registration on Form S-1, file no. 333-35096).
10.32*	Restated Interchange Agreement dated Jan. 16, 2001 between Northern States Power Co. (a Wisconsin corporation) and Northern States Power Co. (a Minnesota corporation) (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
10.33*	500 megawatt System Participation Power Sale Agreement dated July 30, 2002 between Northern States

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	Power Co. (a Minnesota corporation) and the Manitoba Hydro-Electric Board (Exhibit 99.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 25, 2003).
12.01	Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01	Consent of Independent Registered Public Accounting Firm.
31.01	Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.

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SCHEDULE II

NSP-MINNESOTA AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
Years Ended Dec. 31, 2008, 2007 and 2006
(amounts in thousands of dollars)

			Additions
	Balance at beginning of period		Charged to costs and expenses		Charged to other accounts (1)		Deductions from reserves(2)		Balance at end of period
Reserve deducted from related assets:
Allowance for bad debts:
2008	$	20,103	$	25,506	$	6,113	$	26,023	$	25,699
2007	13,408		23,336		5,853		22,494		20,103
2006	10,128		19,972		6,102		22,794		13,408

(1)Recovery of amounts previously written off

(2)Principally bad debts written off or transferred

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NORTHERN STATES POWER COMPANY
	/S/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III Executive Vice President and Chief Financial Officer (Principal Financial Officer)
March 2, 2009

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on March 2, 2009.

/S/ DAVID M. SPARBY	/S/ RICHARD C. KELLY
David M. Sparby President, Chief Executive Officer and Director (Principal Executive Officer)	Richard C. Kelly Chairman and Director
/S/ TERESA S. MADDEN	/S/ BENJAMIN G.S. FOWKE III
Teresa S. Madden Vice President and Controller (Principal Accounting Officer)	Benjamin G.S. Fowke III Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

NSP-Minnesota has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

85